-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, TphfvSW4HFSOfBcNsfFjKL57OCY4RxE0Q7N0NE6JdZl4tZdxGMCjig9TaYEA1NKH YRb7ullhE0ZLVN1fZqyzAA== 0000945764-99-000033.txt : 19990322 0000945764-99-000033.hdr.sgml : 19990322 ACCESSION NUMBER: 0000945764-99-000033 CONFORMED SUBMISSION TYPE: 10-K/A PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 19981231 FILED AS OF DATE: 19990319 FILER: COMPANY DATA: COMPANY CONFORMED NAME: DENBURY RESOURCES INC CENTRAL INDEX KEY: 0000945764 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 000000000 FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K/A SEC ACT: SEC FILE NUMBER: 001-12935 FILM NUMBER: 99569292 BUSINESS ADDRESS: STREET 1: 17304 PRESTON RD STREET 2: STE 200 CITY: DALLAS STATE: TX ZIP: 75252 BUSINESS PHONE: 9726732000 MAIL ADDRESS: STREET 1: 17304 PRESTON RD STREET 2: STE 200 CITY: DALLAS STATE: TX ZIP: 75252 FORMER COMPANY: FORMER CONFORMED NAME: NEWSCOPE RESOURCES LTD DATE OF NAME CHANGE: 19950627 10-K/A 1 AMENDMENT NO. 1 TO FORM 10-K SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 AMENDMENT NO. 1 to FORM 10-K (Mark One) |X| Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 1998 OR |_| Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from _________ to________ Commission file number 33-93722 ------------------------------- DENBURY RESOURCES INC. DENBURY MANAGEMENT, INC. (Exact name of Registrants as specified in its charter) Canada Not applicable Texas 75-2294373 (State or other jurisdiction (I.R.S. Employer of incorporation or organization) Identification No.) 17304 Preston Rd., Suite 200 Dallas, TX 75252 (Address of principal executive offices) (Zipcode) Registrant's telephone number, including area code: (972)673-2000 Securities registered pursuant to Section 12(b) of the Act: ================================================================================ Title of Each Class Name of Each Exchange on Which Registered - -------------------------------------------------------------------------------- Common Shares ( No Par Value) New York Stock Exchange ================================================================================ Securities registered pursuant to Section 12(g) of the Act: 9% Senior Subordinated Notes Due 2008 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] As of February 22, 1999, the aggregate market value of the registrant's Common Shares held by non-affiliates was approximately $78,000,000. The number of shares outstanding of the registrant's Common Shares as of February 22, 1999, was 26,801,680. DOCUMENTS INCORPORATED BY REFERENCE Document Incorporated as to 1. Notice and Proxy Statement 1. Part III, Items 10, 11, 12, for the Annual Meeting of and 13 Shareholders to be held May 19, 1999 Denbury Resources Inc. INDEX TO FORM 10-K/A The undersigned registrant hereby amends and restates the following items of its Annual Report on Form 10-K for the year ended December 31, 1998 as set forth in the pages attached hereto: Item Page - ---- ---- PART II 6. Selected Financial Data.....................................16 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................17 8. Financial Statements and Supplementary Data.................32 Index to Financial Statements and Schedules.......F-1 PART II Item 6. Selected Financial Data - -------------------------------- The following table sets forth five years of selected financial data:
Year Ended December 31, ----------------------------------------------------------------- Amounts in thousands unless noted 1998 1997 1996 1995 1994 - ---------------------------------------------------------------------------------------------------------------------- Operating Data: - --------------- Production (daily) Oil (Bbls)...................................... 13,603 7,902 4,099 1,995 1,340 Gas (Mcf)....................................... 36,605 36,319 24,406 13,271 9,113 BOE (6:1)....................................... 19,704 13,955 8,167 4,207 2,858 Revenue (net of royalties) Oil sales....................................... $ 51,080 $ 49,748 $ 28,475 $ 10,852 $ 6,767 Gas sales....................................... 30,803 35,585 24,405 9,180 5,925 - ---------------------------------------------------------------------------------------------------------------------- Total...................................... $ 81,883 $ 85,333 $ 52,880 $ 20,032 $ 12,692 - ---------------------------------------------------------------------------------------------------------------------- Unit sales price Oil (per Bbl)................................... $ 10.29 $ 17.25 $ 18.98 $ 14.90 $ 13.84 Gas (per Mcf)................................... 2.31 2.68 2.73 1.90 1.78 Net income (loss).................................... $(287,145) $ 14,903 $ 8,744 $ 714 $ 116 Income (loss) per share: Basic........................................... $ (11.08) $ 0.74 $ 0.67 $ 0.10 $ 0.19 Fully diluted................................... (11.08) 0.70 0.62 0.10 0.19 Average common shares outstanding.................... 25,926 20,224 13,104 6,870 6,240 Cash Flow Data: - --------------- Cash flow from operations............................ $ 20,285 $ 62,317 $ 35,185 $ 6,753 $ 6,917 Cash flow from operations excluding the changes in working capital items (1).................... 30,096 56,607 34,140 9,394 6,185 Cash flow used for investing activities ............. 103,797 307,559 88,374 29,084 17,025 Cash flow provided by financing activities........... 76,235 241,115 60,089 28,172 9,108 Balance Sheet Data: - ------------------- Total assets......................................... $ 212,859 $ 447,548 $ 166,505 $ 77,641 $ 48,964 Long-term liabilities................................ 226,436 256,637 7,481 5,077 17,768 Shareholders' equity (deficit) and preferred stock................................ (32,265) 160,223 142,504 68,501 25,962 Per BOE data (6:1) - ------------------ Revenue......................................... $ 11.38 $ 16.75 $ 17.69 $ 13.05 $ 12.17 Production expenses............................. (4.05) (4.36) (4.51) (4.42) (4.13) - ---------------------------------------------------------------------------------------------------------------------- Production netback.............................. 7.33 12.39 13.18 8.63 8.04 General and administrative expenses............. (1.02) (1.30) (1.50) (1.25) (1.12) Interest expenses............................... (2.13) 0.02 (0.26) (1.26) (0.99) - ---------------------------------------------------------------------------------------------------------------------- Cash flow $ 4.18 $ 11.11 $ 11.42 $ 6.12 $ 5.93 - ---------------------------------------------------------------------------------------------------------------------- (1) The Company has included information concerning cash flow before the net change in non-cash working capital balances because it believes that this amount is used by certain investors, particularly in the oil and gas industry, as one measure of an issuer's historical ability to service its debt. This should not be considered in isolation or as a substitute for cash flow from operations prepared in accordance with generally accepted accounting principles.
-16- Item 7. Management's Discussion and Analysis of Financial Condition and Results ----------------------------------------------------------------------- of Operations ------------- Denbury is an independent energy company engaged in acquisition, development and exploration activities in the U.S. Gulf Coast region, primarily onshore in Louisiana and Mississippi. Denbury's primary strategy is to acquire properties which it believes have significant upside potential and increases the value of these properties through the efficient development, enhancement and operation of those properties. Denbury's corporate headquarters is in Dallas, Texas and it has two primary field offices in Houma, Louisiana and Laurel, Mississippi. OVERVIEW. The Company's current financial condition and 1998 operating results have been defined by the deep and rapid fall in oil prices during 1998. This price decline has significantly reduced the Company's cash flow and results of operations and increased the Company's debt levels. While oil prices are at one of the lowest levels in recent history, as a multiple of cash flow the Company's debt is at an historic high. In response to these rapid changes, during the second half of 1998 the Company eliminated its horizontal drilling program and exploration expenditures and significantly reduced its overall expenditure level. This reduction in expenditures included its planned development program of the Heidelberg Field acquired from Chevron in December 1997 as low prices made the drilling of new oil wells uneconomical. Starting in June of 1998, the Company entered into financial collars to hedge its gas production, and in the fourth quarter of 1998 renegotiated its Mississippi oil sales contracts. Furthermore, the Company reached an agreement to sell $100 million of stock to the Texas Pacific Group ("TPG"), its largest shareholder, which is expected to close in April 1999, subject to shareholder approval. Funds made available by this sale should enable the Company to make favorable acquisitions in an environment in which capital resources are limited. 1998 Activity CHEVRON HEIDELBERG FIELD ACQUISITION. In late December 1997, the Company acquired oil properties in the Heidelberg Field, Jasper County, Mississippi, from Chevron for approximately $202 million, the largest acquisition by the Company to date. To fund the acquisition, the Company amended and restated its bank credit facility and at the same time increased the facility size from $150 million to $300 million. As of December 31, 1997, the Company owed $240 million on this facility with a borrowing base of $260 million. FEBRUARY 1998 PUBLIC DEBT AND EQUITY OFFERING. To obtain permanent financing for the Chevron acquisition, the Company made a public debt and equity offering which closed in late February. The Company sold 5,240,780 common shares at a price of $16.75 per share ($15.955 per share net to the Company) to the public and concurrently sold the Texas Pacific Group ("TPG"), the Company's largest shareholder, 313,400 common shares. The net proceeds to the Company from the equity offering and TPG purchase were approximately $88.6 million, before offering expenses. At the same time, the Company sold $125 million in aggregate principal amount of 9% Senior Subordinated Notes Due 2008, which were issued by its wholly owned subsidiary, Denbury Management, Inc. These notes contain typical debt covenants, including covenants that limit (i) indebtedness, (ii) certain payments including dividends, (iii) sale/leaseback transactions, (iv) transactions with affiliates, (v) liens, (vi) asset sales, and (vii) mergers and consolidations. The net proceeds to the Company from the debt offering were approximately $121.8 million, before offering expenses. The total net proceeds from the debt and equity offerings were approximately $209.5 million after deducting total offering expenses of $900,000. These proceeds were used to reduce the amount borrowed under the Company's bank credit facility, leaving an outstanding balance of $40 million as of the end of February, after an additional $9.5 million was borrowed during the first two months of 1998. Simultaneously, the Company's bank borrowing base was reduced to $165 million, leaving $125 million available on the line. -17- FIRST QUARTER CEILING TEST. Oil prices were on a steady decline throughout most of 1998. The oil prices used in the December 31, 1997 reserve report were based on a NYMEX price of $18.32 per barrel of oil ("Bbl"). By March 31, 1998, the comparable price was $15.61. Line graph showing three respective oil price postings from January 1996 through December 1998 by month: Jan-96 Feb-96 Mar-96 Apr-96 May-96 Jun-96 Jul-96 Aug-96 NYMEX 18.70 18.78 21.18 23.29 21.09 20.43 21.25 21.91 KOCH WTI 17.35 17.21 19.59 21.77 19.52 18.84 19.74 20.37 EOTT MS LT SR 14.82 14.70 17.09 19.27 17.02 16.33 17.20 17.85 Sep-96 Oct-96 Nov-96 Dec-96 Jan-97 Feb-97 Mar-97 Apr-97 May-97 Jun-97 23.93 24.89 23.55 25.12 25.18 22.17 20.97 19.73 20.87 19.22 22.25 22.85 21.99 23.39 23.48 20.47 19.08 18.11 18.98 17.18 19.75 20.84 19.49 20.89 20.98 17.97 16.08 15.03 15.96 14.17 Jul-97 Aug-97 Sep-97 Oct-97 Nov-97 Dec-97 Jan-98 Feb-98 Mar-98 Apr-98 19.66 19.95 19.78 21.28 20.22 18.32 16.73 16.08 15.05 15.47 17.52 17.76 17.63 19.17 17.99 16.18 14.56 13.88 12.76 13.13 14.52 14.76 14.63 16.17 14.99 13.17 11.55 10.71 9.44 9.63 May-98 Jun-98 Jul-98 Aug-98 Sep-98 Oct-98 Nov-98 Dec-98 14.93 13.67 14.08 13.38 14.98 14.46 12.96 11.24 12.52 11.06 11.51 10.88 12.39 11.87 10.34 8.60 9.02 7.53 8.00 7.38 8.89 8.37 6.84 5.10 Under full cost accounting rules, each quarter the Company is required to perform a ceiling test calculation. Although the Canadian accounting approach is slightly different, the Securities and Exchange Commission ("SEC") requires that the full cost pool carrying values do not exceed a company's future net revenues from its proved reserves discounted at 10% per annum using constant current product prices. The Company excluded the Heidelberg Field from the full cost ceiling test as of March 31, 1998 as it believed that, based on its success with similar properties in Mississippi, the value of this property was at least equal to its carrying cost. As of March 31, 1998, inclusion of the Heidelberg Field in the ceiling test would have resulted in a $35 million writedown. SECOND QUARTER. During the second quarter of 1998, oil prices continued to decline, with a drop of approximately $1.50 in the NYMEX oil price from March 31 to June 30, 1998. Furthermore, the gap between the NYMEX oil price and the net realized price widened, causing the net realized price at Heidelberg Field to drop approximately $1.00 per Bbl more than the decline in the NYMEX price. In response to the decline in oil prices, the Company announced in June 1998 that it was curtailing the horizontal drilling program on its oil properties and would generally focus on projects that could impact future years, such as expenditures on facilities, waterflood units, and a few higher potential projects. This included the postponement of 22 of 32 originally scheduled horizontal wells at Heidelberg Field. However, by June 30, 1998, the Company had already spent a total of $76.3 million on capital expenditures, of which $13.2 million related to acquisitions. The exploration and development expenditures included approximately $38.0 million spent on drilling, $14.1 million spent on geological, geophysical and acreage expenditures and $11.0 million spent on workover costs. WRITEDOWN AT JUNE 30, 1998. This curtailment in activity included the recently acquired Heidelberg Field. As a result of this curtailment, it was unlikely that the proved reserves and production from this property would increase as quickly as originally anticipated, thus causing a decline in the current value of this property. Therefore, as of June 30, 1998, the Company included the Heidelberg Field in the full cost pool for its ceiling test, which coupled with the reduction in oil prices, resulted in a $165 million writedown of the full cost pool as of that date. This ceiling test was computed using June 30, 1998 prices, which were equivalent to a NYMEX oil price of $14.00 per Bbl and an average net realized oil price of $8.90 per Bbl, a drop of approximately $5.53 per Bbl from the net prices used in the December 31, 1997 reserve report. PRODUCT PRICE HEDGES. In further response to the decline in oil prices and to mitigate additional price-related negative effects on the Company's cash flow, in June and July 1998, the Company entered into two no-cost financial contracts ("collars") to hedge a total of 40 million cubic feet of natural gas per day ("MMcf/d"). The first natural gas contract for 35 MMcf/d covers the period from July 1998 to June 1999 and has a floor price of $1.90 per million -18- British Thermal Units ("MMBtu") and a ceiling price of $2.96 per MMBtu. The second natural gas contract for five MMcf/d covers the period from September 1998 to August 1999 and has a floor price of $1.90 per MMBtu and a ceiling price of $2.89 per MMBtu. During December 1998, the Company extended these natural gas hedges through December 2000 by entering into an additional no-cost collar with a floor price of $1.90 per MMBtu and a ceiling price of $2.58 per MMBtu for the period of July 1999 through December 2000. This contract hedges 25 MMcf/d for the months of July and August 1999 and 30 MMcf/d for each month thereafter. The Company collected $175,200 on these financial contracts during 1998 and these contracts cover over 100% of the Company's current net natural gas production. For 1998, the Company's natural gas production made up 31% of the Company's total production on a BOE basis. Based on the futures market prices at December 31, 1998, the Company would not receive or pay any amounts under these commodity contracts even though they covered more than the Company's production because prices at December 31, 1998 were within the contract collars. Bar graph showing bank debt in millions of dollars as of the dates shown. 3/31/98 6/30/98 9/30/98 12/31/98 ------- ------- ------- -------- Bank debt 40.0 70.0 90.0 100.0 The Company also reviewed its oil purchase contracts and in the fourth quarter entered into new contracts on virtually all of its Mississippi oil production. These new contracts, which are generally for a period of twelve to twenty-four months, changed the price methodology on which the contracts are based and provided for protection to the Company against any further widening of the gap between the local posted price and NYMEX. Certain of the contracts also implemented a price floor of between $8.00 and $10.00 per Bbl which equates to a NYMEX oil price of between $15.00 and $16.00 per Bbl. As compensation for the price floors, the contracts provide that the premiums received on the posted prices decrease as oil prices rise. The contracts with floor prices covered approximately 45% of the Company's oil production, as of January 31, 1999. $35 MILLION REDUCTION OF BORROWING BASE AS OF OCTOBER 1. The Company's borrowing base was also affected by the drop in price. The credit agreement stipulates that the borrowing base will be reviewed every six months and a new borrowing base set each April 1 and October 1. The banks made their semi-annual review in September, based on the June 30, 1998 proved reserves and other assets, and reduced the borrowing base from $165 million to $130 million with the reduction almost entirely due to the lower product prices. This left the Company with $40 million of borrowing capacity as of September 30. Bar and line graph showing capital expenditures and cash flow from operations in millions of dollars for each of the four quarters ended December 31, 1998. 3/31/98 6/30/98 9/30/98 12/31/98 ------- ------- ------- -------- Capital expend. 26.4 49.8 17.4 9.0 Cash flow 11.5 9.1 6.8 2.8 CAPITAL EXPENDITURES - SECOND HALF OF 1998. During the third quarter of 1998, the Company reduced spending to a total of $17.4 million (compared to $76.3 million during the first six months) and also shifted the focus from Mississippi oil properties to Louisiana gas properties. Approximately 62% of the third quarter capital expenditures were in Louisiana, as compared to approximately 16% during the prior six months. However, the overall results of the Louisiana development program were disappointing due to an unsuccessful development well and faster than anticipated production declines on certain other properties. With the continued low oil prices, reduced cash flow and rising debt levels, during the latter part of the third quarter the Company took additional steps to reduce its capital expenditures. For the fourth quarter, expenditures dropped to $9.0 million, or $36.0 million on an annualized basis, a level that more closely approximated available cash flow. -19- In addition to its internal capital expenditure program, the Company has historically required capital for acquisitions of producing properties, which have been a major factor in the Company's growth during recent years. Because of the downturn in the oil and gas industry during 1998 as a result of the decreases in oil and natural gas prices, the Company believes that 1999 is an excellent time to make attractive acquisitions. However without additional capital, it is doubtful that the Company could make any meaningful acquisitions. As of September 30, 1998, the Company had minimal working capital with $90 million of bank debt outstanding and $125 million outstanding on its 9% Senior Subordinated Notes Due 2008. Although the Company had a bank borrowing base of $130 million as determined by the banks in their October 1, 1998 redetermination, the Company expected this borrowing base to be reduced again at the next scheduled redetermination on April 1, 1999. PROPOSED $100 MILLION SALE OF SHARES TO TPG. During the last quarter of 1998, the Company began to seek out additional sources of capital and in December 1998, the Company negotiated a stock purchase by its largest shareholder, TPG of 18,552,876 common shares of the Company at $5.39 per share for an aggregate consideration of $100 million. The consummation of this stock sale is conditioned upon the approval of the sale by the shareholders of the Company, completion of an amendment to the Company's bank agreement, the absence of a material adverse change, as that term is defined in the agreement, plus satisfaction of other conditions. The Company completed an amendment to its bank credit facility as of February 19, 1999 (see "February 1999 Amendment to Bank Credit Facility" below) and is seeking shareholder approval at a special meeting of the shareholders currently expected to be held in April 1999. The Company anticipates that all other conditions will be satisfied by the date of the special shareholders meeting. If this sale of stock is consummated, TPG will gain control of the Company with ownership that will increase from approximately 32% to approximately 60%. Although the Company does not expect this transaction to result in any immediate changes to its directors, management or operations, TPG will have adequate voting power to control the election of directors, to determine the corporate and management policies of the Company and to effect the shareholder approval of a merger, consolidation or sale of all or substantially all of the assets of the Company. The Company expects to close this stock sale in April 1999 and plans to pursue acquisitions with funds made available under its credit facility as a result of the sale. However, there can be no assurance that the stock sale will close. In addition, there is no assurance that the Company will have enough capital available to fund desired acquisitions, that funds will still be available from the banks by the time the Company locates acceptable acquisitions, or that suitable acquisitions can even be identified and completed. If acquisitions are made, they may not be successful in achieving the Company's desired profitability objectives. In the current price environment, without suitable acquisitions or the capital to fund such acquisitions, the Company's future growth could be limited or even eliminated. ADDITIONAL WRITEDOWN AT DECEMBER 31, 1998. As of December 31, 1998, oil prices had deteriorated further to a NYMEX price of approximately $12.00 per Bbl and an average net realized price of $7.37 per Bbl, a drop of $7.06 in the average net realized price since December 31, 1997. As a result of this decrease in product prices, along with some downward revisions in the Company's proven reserves (see "Results of Operations - Depreciation, Depletion and Site Restoration") the current value (using the year-end oil and natural gas prices) of the Company's reserves as of December 31, 1998 are not sufficient to repay debt. Based on this reserve forecast and after considering the effects of administrative and financing costs, under Canadian GAAP the full balance of oil and gas properties would be written off. As it is expected by management that the prices realized over the remaining life of the reserves will be higher than the year-end prices, an average NYMEX oil price of $14.00 per Bbl (a price slightly less than the 1998 average price) was used in determining the Canadian GAAP ceiling test at year-end. Based on this $14.00 NYMEX price and using undiscounted future net revenues after considering the effects of administrative and interest costs, an additional writedown of $115 million was recognized for the fourth quarter, or a total writedown for the year of $280 million. This -20- writedown is the same as that required under U.S. GAAP using the year-end $12.00 NYMEX price and the net present value of the reserves without consideration of administrative and interest costs. Although this writedown reduced the Company's capital below the threshold required by the Company's banks, the bank amendment (see "February 1999 Amendment to Bank Credit Facility") completed on February 19, 1999, modified this test such that the Company is now in compliance. These charges are non-cash items and should not have any direct impact on the Company's liquidity. FEBRUARY 1999 AMENDMENT TO BANK CREDIT FACILITY. On February 19, 1999, the Company completed an amendment to its credit facility with Bank of America, as agent for a group of eight other banks, thereby meeting one of the required conditions for the sale of stock to TPG. This amendment sets the borrowing base at $110 million, of which $60 million was considered by the banks to be within their normal credit guidelines. The credit facility continues with its other restrictions such as a prohibition on the payment of dividends and a prohibition on most debt, lien and corporate guarantees. This amendment: o provided certain relief on the minimum equity and interest coverage tests; o changed the facility to one secured by substantially all of the Company's oil and natural gas properties; o requires that as long as the borrowing base is larger than a borrowing base that conforms to normal credit guidelines (currently $60 million), that at least 75% of the funds borrowed subsequent to the closing of the proposed TPG purchase must be used for either qualify- ing acquisitions or capital expenditures made to maintain, enhance or develop its proved reserves; o increased the interest rate to a range from LIBOR plus 1.0% to LIBOR plus 1.75% depending on the amounts outstanding and LIBOR plus 2.125% if the outstanding debt exceeds the borrowing base under normal credit guidelines, currently set at $60 million; and o provided that a failure to close the TPG stock sale before June 16, 1999 would be an event of default. The Company expects that approximately $10 million will be outstanding on the facility after the proposed sale of stock to TPG, leaving a total borrowing capacity of $100 million, an amount approximately equal to the anticipated proceeds from the TPG stock sale. The next scheduled re-determination of the borrowing base will be as of October 1, 1999, based on June 30, 1999 assets and proven reserves. If prices remain low or deteriorate further, it is possible that the banks could further reduce the borrowing base at that time. Although the Company is not in default of any of its debt covenants at the present time and has been afforded certain relief on the covenants as part of the amendment, it is possible that a continued low oil price for an extended period of time could cause the Company to violate its agreements in the future. CAPITAL RESOURCES AND LIQUIDITY As more fully described under "Results of Operations" below, between 1997 and 1998, the Company's average net oil product prices decreased 40% ($6.96 per Bbl) and natural gas product prices declined by 14% ($0.37 per Mcf). Based on the 1998 production levels, these reduced product prices caused 1998 oil revenue to decrease by approximately $35 million over what it would have been using 1997 average prices and 1998 gas revenue to decrease by approximately $5 million based on the same assumptions. Due to this drop in oil and natural gas prices, the Company's cash flow and results of operations have been significantly reduced during 1998. This reduction in cash flow has also contributed to an increase in the Company's debt levels during the year. While oil prices are at one of the lowest levels in recent history, as a multiple of cash flow the Company's debt is at an historic high. Because of the downturn in the oil and gas industry during 1998 as a result of the decreases in oil and natural gas prices, the Company believes that 1999 is an excellent time to make attractive acquisitions. However without additional -21- capital, it is doubtful that the Company could make any meaningful acquisitions. In late 1998, the Company sought additional capital in order to have funds to pursue acquisitions and entered into an agreement to sell $100 million of common shares to TPG (see "Proposed $100 Million Sale of Shares to TPG" above). As compared to 1998, the Company's 1999 development budget has been sharply reduced in order to bring expenditures more in line with available cash flow. Currently, the capital budget for 1999, excluding acquisitions, is between $20 million and $35 million, depending on the product prices at the time. The drilling portion of the budget is the biggest variable, as it is not economical to do development drilling on oil properties at the current price level. However, should prices improve, the Company has built a significant inventory of oil projects that it can commence, subject to the availability of capital. Although the level of the Company's projected cash flow is highly variable and difficult to predict as it is dependent on product prices, the success of its drilling and other developmental work and other factors, the Company does not expect its 1999 development spending to cause debt to increase substantially. However, this reduced spending level will cause a corresponding reduction in the previously anticipated production levels and related cash flow and it is possible that the Company will not be able to maintain its current production levels or replace its reserves with this reduced level of capital expenditures. Although oil prices have fallen substantially during 1998, the Company does not believe that oil prices will remain this low indefinitely. Any increase in price would have a positive effect on both results of operations and cash flow and the quantity and value of the Company's proved reserves. As of December 31, 1998, the current net present value (using the year-end oil and natural gas prices) of the Company's reserves are insufficient to repay the senior bank loan, the 9% Senior Subordinated Notes due 2008 and the related interest costs, which casts substantial doubt upon the ability to continue operation in the foreseeable future and to be able to realize assets and satisfy liabilities in the normal course of business. The Company's ability to continue as a going concern is dependent upon the completion of the sale of stock to TPG (see "Proposed $100 Million Sale of Shares to TPG") or an increase in oil and natural gas prices. Although the Company believes, based upon all the factors known to management at this time, that the stock sale will be approved by shareholders and thus will occur, if this proposed sale of stock does not close or oil and natural gas prices do not increase to enable the repayment of the debt and interest costs, the Company will be in default of its bank credit agreement. If this default were to cause its banks to significantly reduce the borrowing base under its credit agreement or accelerate the loan, the Company would not have sufficient liquid assets to immediately repay or substantially reduce the loan. In this event, the Company would attempt to negotiate an accommodation with the bank, which cannot be assured, and might be required to sell some of its properties to repay the loan. If the borrowing base is not reduced and the loan is not accelerated and based on current product prices and production levels, the Company believes it would have sufficient cash flow from operations to meet its obligations and continue operations during 1999, provided that the Company further reduces its capital expenditures to a level equal to cash flow; however, this reduction in expenditures makes it unlikely that the Company would be able to maintain positive cash flow beyond 1999, as production would be expected to decline over time. If the Company were unable to continue as a going concern, then significant adjustments would be necessary to the Company's financial statements to properly reflect a need to liquidate assets in order to repay debt, to reflect all debt as current and other potential adjustments due to the changes in operations. Sources and Uses of Funds During 1998, the Company spent approximately $89.0 million on exploration and development activities and approximately $13.7 million on acquisitions. The exploration and development expenditures included approximately $53.0 million spent on drilling, $17.8 million on geological, geophysical and acreage expenditures and $18.2 million on workover costs. These expenditures were funded by bank debt ($60.0 million), cash flow from operations ($20.3 million) and from cash and other sources ($22.4 million). Of the total 1998 expenditures of $102.7 million, approximately 26% or $27 million of the development expenditures were directed to long term projects such as production facilities and waterflood units, plus undeveloped properties such as acreage and seismic. Expenditures on these types of projects were not expected to benefit the Company until 1999 or beyond. Bar graph showing development and acquisition expenditures by year in millions of dollars for the three years ended December 31, 1998 1996 1997 1998 ---- ---- ---- Development 38.5 81.3 89.0 Acquisitions 48.4 224.1 13.7 ---- ----- ----- Total 86.9 305.4 102.7 ==== ===== ===== During 1997, the Company spent approximately $81.3 million on oil and natural gas exploration and development activities and approximately $224.1 million on acquisitions, the majority of which related to the $202 million acquisition from Chevron in December. The exploration and development expenditures included approximately $55.9 million spent on drilling, $9.0 -22- million on geological, geophysical and acreage expenditures and the balance of $16.4 million was spent on workover costs. These expenditures were funded by available cash ($3.2 million), cash flow from operations ($62.3 million) and bank debt ($239.9 million). During 1996, the Company spent approximately $33.4 million on oil and natural gas exploration and development expenditures, $37.2 million on the acquisition of properties from Amerada Hess, $11.2 million on other oil and natural gas acquisitions, and approximately $5.1 million on geological, geophysical and acreage expenditures. The exploration and development expenditures included $15.5 million spent on drilling and the balance of $17.9 million was spent on workover costs. These expenditures were funded during the year by bank debt, available cash and cash flow from operations, although the bank debt was retired with the proceeds from a public offering of common shares in October 1996. RESULTS OF OPERATIONS Operating Income While production volumes have increased substantially each year for the past three years and were 41% higher on a BOE basis during 1998 as compared to 1997, operating income decreased slightly between 1997 and 1998 due to a 32% decline in product prices (on a BOE basis), as outlined in the following chart.
Year Ended December 31 - ------------------------------------------------------------------------------------------------------ 1998 1997 1996 - ------------------------------------------------------------------------------------------------------ Average daily production volume: Bbls 13,603 7,902 4,099 Mcf 36,605 36,319 24,406 BOE 19,704 13,955 8,167 - ------------------------------------------------------------------------------------------------------ Unit prices Oil price per Bbl $ 10.29 $ 17.25 $ 18.98 Gas price per Mcf 2.31 2.68 2.73 - ------------------------------------------------------------------------------------------------------ Netback per BOE Sales price 11.38 16.75 17.69 Production expenses (4.05) (4.36) (4.51) - ----------------------------------------------------------------------------------------------------- $ 7.33 $ 12.39 $ 13.18 - ------------------------------------------------------------------------------------------------------ Operating income (thousands) Oil sales $ 51,080 $ 49,748 $ 28,475 Natural gas sales 30,803 35,585 24,405 Less production expenses (29,162) (22,218) (13,495) - ------------------------------------------------------------------------------------------------------ Operating income $ 52,721 $ 63,115 $ 39,385 - ------------------------------------------------------------------------------------------------------ (1) Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of natural gas ("BOE").
-23- PRODUCTION. The production increases have been fueled by a combination of internal growth and acquisitions. During the last three years, the Company has made two key acquisitions, one for $37 million from Amerada Hess in May 1996 and the latter for $202 million from Chevron in December 1997. The properties acquired from Amerada Hess contributed an average of 2,017 BOE/d to 1996 production rates, 5,090 BOE/d in 1997 and 8,100 BOE/d in 1998. The initial production rates on these properties was 2,945 BOE/d for the first two months of ownership, with virtually all of the subsequent production increases coming from internal development and exploitation of these properties. The production on these Hess properties peaked in the second quarter of 1998 at 9,730 BOE/d. During the third quarter of 1998, the average production on these properties began to decline and for the fourth quarter averaged 5,730 BOE/d. The decrease is primarily due to production declines on several horizontal oil wells drilled at Eucutta Field in late 1997 and early 1998 and the lack of subsequent development work to replace this production. Bar graph showing average Company production for each of the quarters during the three years ended December 31, 1998. 3/31/96 6/30/96 9/30/96 12/31/96 3/31/97 6/30/97 9/30/97 ------- ------- ------- -------- ------- ------- ------- BOE/d 5,453 7,841 9,208 10,132 12,256 13,404 14,195 12/31/97 3/31/98 6/30/98 9/30/98 12/31/98 -------- ------- ------- ------- -------- BOE/d 15,922 21,441 21,927 19,402 16,108 The Company also increased production in 1998 from the Heidelberg Field, acquired from Chevron in December 1997, the largest acquisition to date by the Company. At the time of acquisition, this property was producing approximately 2,900 BOE/d. As a result of development work on this field, particularly during the first six months of 1998, which included eight horizontal wells, production for the year averaged 3,760 BOE/d and 4,250 BOE/d for the fourth quarter. During the second half of 1998, due to low oil prices the Company postponed the drilling of 14 other horizontal wells originally planned for 1998 and, unless prices recover, is not expected to drill any horizontal wells at this field during 1999. Because of this reduction in planned drilling expenditures, the production is not expected to materially change at Heidelberg Field during 1999. The Company has not halted its expenditures on the East Heidelberg waterflood unit and other facilities, although these expenditures usually do not generate immediate increases in production. The Company has begun to see some limited production increases from the waterflood and expects a gradual increase in the production response from the waterflood during 1999, although it is difficult to predict the magnitude of such a response. Although the Company's overall annual production rates for 1998 increased substantially over the 1997 average, during the third and fourth quarter of 1998 the Company experienced declines in its production rates for the first time in several years. This was due to (i) shutting in uneconomic wells, (ii) declines on existing production, particularly the horizontal wells, and (iii) the postponement of several oil development projects due to the low oil prices. -24- Bar graph showing average oil prices received by the Company for each of the three years ended December 31, 1998. 1996 1997 1998 ---- ---- ---- Dollar per Bbl 18.98 17.25 10.29 REVENUE. Oil and natural gas revenue increased between 1996 and 1997 as a result of the increase in production, although the production increase was partially offset by a 5% decline in the average product prices (on a BOE basis). However, between 1997 and 1998, even though production increased 41%, oil and natural gas revenue actually dropped 32% due to a 40% drop ($6.96 per Bbl) in the average oil prices and a 14% drop ($0.37 per Mcf) in the average natural gas prices. Based on the 1998 production levels, these reduced product prices caused 1998 oil revenue to decrease by approximately $35 million over what it would have been using 1997 average prices and 1998 gas revenue to decrease by approximately $5 million based on the same assumptions. Bar graph showing average gas prices received by the Company for each of the three years ended December 31, 1998. 1996 1997 1998 ---- ---- ---- Dollar per Mcf 2.73 2.68 2.31 OPERATING EXPENSES. The overall production and operating expenses increased each year primarily due to an increase in the number of properties, principally from the Hess and Chevron acquisitions. Even though the number of properties increased, production increased at a faster pace allowing the Company to reduce its production and operating expenses on a BOE basis by 3% between 1996 and 1997 and a further reduction of 7% between 1997 and 1998. For the properties acquired in the Hess acquisition, the operating expenses declined from the 1996 level of $5.35 per BOE to $4.56 per BOE for 1997 and were further reduced to $3.39 for 1998. This reduction is largely attributable to the Company's emphasis in 1997 and early 1998 on horizontal drilling on these properties and the resulting increases in production. The Company was also able to lower overall costs during the second half of 1998 by shutting in uneconomical wells and through other general cost saving measures, although the cost per BOE increased in the fourth quarter, when compared to the first nine months, due to the decline in overall production rates. The Company has been able to achieve these reductions in operating expenses per BOE even though the Company's production has become even more weighted towards oil (which has higher operating costs) with approximately 69% of the Company's 1998 production coming from oil as compared to 57% during 1997 and 50% during 1996. The operating expenses per BOE for the properties acquired in the Chevron acquisition averaged $5.04 per BOE for 1998, a significant decline from the average of approximately $6.38 per BOE when the properties were owned by Chevron. This reduction was accomplished because of the increased production levels and by general cost saving measures. -25- General and Administrative Expenses General and administrative ("G&A") expenses have increased as outlined below along with the Company's growth.
Year Ended December 31, - ------------------------------------------------------------------------------------------------ 1998 1997 1996 - ------------------------------------------------------------------------------------------------ Net G&A Expenses (Thousands) Gross expenses $ 18,962 $ 13,909 $ 8,407 State franchise taxes 785 428 213 Operator overhead charges (9,749) (5,502) (2,916) Capitalized exploration expenses (2,657) (2,225) (1,224) - ------------------------------------------------------------------------------------------------ Net expenses $ 7,341 $ 6,610 $ 4,480 - ------------------------------------------------------------------------------------------------ Average G&A cost per BOE $ 1.02 $ 1.30 $ 1.50 Employees as of December 31 205 157 122 - ------------------------------------------------------------------------------------------------
On a BOE basis, G&A costs decreased 13% between 1996 and 1997 and declined an additional 22% between 1997 and 1998. These savings were realized, in part because of increased production on both an absolute and per well basis and also from general cost saving measures, particularly during the second half of 1998. Furthermore, the respective well operating agreements allow the Company, when it is the operator, to charge a well with a specified overhead rate during the drilling phase and to also charge a monthly fixed overhead rate for each producing well. As a result of the increased drilling activity in 1997 and early 1998 and the addition of several producing wells acquired in the Chevron acquisition in December 1997, the percentage of gross G&A recovered through these types of allocations (listed in the above table as "Operator overhead charges") increased when compared to prior periods. A total of 10 wells were drilled during 1996, 44 during 1997 and 42 during 1998. During 1996, approximately 35% of gross G&A was recovered by operator overhead charges, while during 1997 this recovery increased to 40% and further increased to 51% during 1998. This significant increase in overhead recoveries is not expected to continue in 1999 as a result of the curtailed drilling expenditures on oil properties, thus reducing the amount of overhead recovered from drilling wells which may result in a net increase in future G&A expenses. Interest and Financing Expenses
Year Ended December 31, - -------------------------------------------------------------------------------------------------- Amounts in Thousands Except Per Unit Amounts 1998 1997 1996 - -------------------------------------------------------------------------------------------------- Interest expense $ 17,534 $ 1,111 $ 1,993 Non-cash interest expense (627) (91) (459) - -------------------------------------------------------------------------------------------------- Cash interest expense 16,907 1,020 1,534 Interest and other income (1,623) (1,123) (769) - -------------------------------------------------------------------------------------------------- Net interest expense (income) $ 15,284 $ (103) $ 765 - -------------------------------------------------------------------------------------------------- Average interest expense (income) per BOE $ 2.13 $ (0.02) $ 0.26 Average debt outstanding 205,087 12,700 19,500 Average interest rate 8.1% 6.9% 7.9% - -------------------------------------------------------------------------------------------------- Imputed preferred dividend $ - $ - $ 1,281 Loss on early extinguishment of debt - - 440 - --------------------------------------------------------------------------------------------------
-26- During the first half of 1996 and 1997, the Company had minimal debt outstanding as virtually all of the bank debt had been retired during the fourth quarters of 1995 and 1996. In 1995, the bank debt was repaid with proceeds from the December 1995 private placement of equity with TPG and in 1996 with proceeds from a public offering of common shares completed in October 1996. However, in 1996, the Company did incur debt late in the second quarter to fund property acquisitions, the largest of which was the Hess acquisition, and during 1997, the Company borrowed $202 million of its December 31, 1997 outstanding balance of $240 million late in the fourth quarter to fund the Chevron acquisition. The $240 million of bank debt remained outstanding for only two months. On February 26, 1998 this bank debt was repaid with proceeds from a debt and equity offering, leaving a bank balance of $40 million for the rest of the first quarter of 1998, plus $125 million of public debt from the issuance of the 9% Senior Subordinated Notes. This bank debt increased throughout the year, from $40 million as of March 31, 1998 to $70 million as of June 30, to $90 million as of September, to its balance of $100 million as of December 31, 1998. These transactions resulted in substantially higher interest expense for 1998 as compared to 1997, on both an absolute and BOE basis. During 1996, the Company recognized $1.3 million of charges representing the imputed preferred dividend until October 30, 1996 when the convertible preferred was converted into 2.8 million common shares. During 1996, the Company also had a $440,000 charge relating to a loss on early extinguishment of debt. These costs related to the remaining unamortized debt issue costs of the Company's prior credit facility which was replaced in May 1996. Depletion, Depreciation and Site Restoration Depletion, depreciation and amortization ("DD&A") has increased along with the additional capitalized cost and increased production. DD&A per BOE, excluding the writedown, has increased from $5.99 for 1996 to $6.42 for 1997 and $7.26 for 1998, primarily as a result of the decline in oil price. The reduced oil price causes wells to reach the end of their economic life much sooner and also makes certain proved undeveloped locations uneconomical, both of which reduce the reserve quantities. The oil prices used in the December 31, 1996 reserve report were based on a West Texas Intermediate price of $23.39 per Bbl, with these representative prices adjusted by field to arrive at the appropriate corporate net price in accordance with the rules of the Securities and Exchange Commission. However, this price was reduced to $16.18 per Bbl at December 31, 1997 and further reduced to $9.50 as of December 31, 1998. The Company's average net realized oil prices used in the December 31, 1996, 1997 and 1998 reserve report were $21.73, $14.43 and $7.37, respectively. This reduction in the reserves due to price amounted to approximately 1.6 million BOE between 1996 and 1997 and 15.1 million BOE between 1997 and 1998. The Company also lost approximately 9.8 million BOE in 1998 which in part was also related to price, in that the Company has postponed or canceled repairs and upgrades on oil wells resulting in steeper declines. Also contributing to downward revisions in 1998 were poor performances on three of the Company's gas properties in Louisiana and an unsuccessful development well also in Louisiana. The loss in reserves due to price caused DD&A to increase approximately $0.29 per BOE during 1997 and $0.89 per BOE for 1998. The DD&A rate was also reduced in 1998 due to the reduction of depletable costs as a result of the $165 million writedown as of June 30, 1998. Under Canadian full cost accounting rules, the Company is required to perform a ceiling test annually; however, significant changes in estimates of reserves, prices, income taxes and other important factors are considered on a quarterly basis. Under U.S. full cost accounting rules, each quarter the Company is required to perform a ceiling test calculation. See "Full Cost Ceiling Test" for a discussion of the writedowns taken at June 30, 1998 and December 31, 1998. -27- The Company also provides for the estimated future costs of well abandonment and site reclamation, net of any anticipated salvage, on a unit-of-production basis. This provision is included in the DD&A expense and has increased each year along with an increase in the number of properties owned by the Company.
Year Ended December 31, - -------------------------------------------------------------------------------------------------------- Amounts in Thousands Except Per Unit Amounts 1998 1997 1996 - -------------------------------------------------------------------------------------------------------- Depletion and depreciation $ 51,815 $ 32,311 $ 17,533 Writedown of oil and gas properties 280,000 - - Site restoration provision 419 408 371 - -------------------------------------------------------------------------------------------------------- Total amortization $ 332,234 $ 32,719 $ 17,904 - -------------------------------------------------------------------------------------------------------- Average DD&A cost per BOE $ 46.20 $ 6.42 $ 5.99 - --------------------------------------------------------------------------------------------------------
Income Taxes Due to a net operating loss of the U.S. subsidiary each year for tax purposes, the Company does not have any current tax provision. The deferred income tax provision as a percentage of net income varies slightly depending on the mix of Canadian and U.S. expenses. The 1996 rate was the highest of the three years as outlined below due to the non-deductible imputed preferred dividend and interest on the subordinated debt during that year. In addition, as a result of the previously discussed $280.0 million writedown of its oil and natural gas properties and the resultant net pre-tax loss of $302.8 million for the year ended December 31, 1998, an income tax provision for 1998 using the effective tax rate of 37% would have resulted in a $96.4 million deferred tax asset. Since the Company currently has a large tax net operating loss, it was uncertain whether this total tax asset could ultimately be realized, particularly in light of the low oil and natural gas prices. As such, the Company fully impaired the deferred tax asset, resulting in a 5% effective tax benefit rate for the year.
Year Ended December 31, - ------------------------------------------------------------------------------------------------------- 1998 1997 1996 - ------------------------------------------------------------------------------------------------------- Deferred income tax (benefit) provision (thousands) $ (15,620) $ 8,895 $ 5,312 Average income tax costs (benefit) per BOE $ (2.17) $ 1.75 $ 1.78 Effective tax rate 5% 37% 38% - -------------------------------------------------------------------------------------------------------
Results of Operations Bar graph showing cash flow from operations (excluding the change in working capital items)for each of the three years ended December 31, 1998. 1996 1997 1998 ---- ---- ---- Millions of Dollars 34.1 56.6 30.1 Between 1996 and 1997, the operating results showed strong improvement, primarily due to the increases in production as previously discussed. However, even though production was up during 1998 and most expenses, other than interest expense, improved on a BOE basis, as a result of the decline in product prices, net income and cash flow from operations decreased substantially on both a gross and per share basis between 1997 and 1998 as outlined below. In addition, during 1998, the Company incurred a $280.0 million non-cash charge to operations to writedown the carrying value of its oil and natural gas properties as previously discussed. -28-
Year Ended December 31, - ------------------------------------------------------------------------------------------------------- Amounts in Thousands Except Per Share Amounts 1998 1997 1998 - ------------------------------------------------------------------------------------------------------- Net income (loss) $ (287,145) $ 14,903 $ 8,744 Net income (loss) per common share: Basic $ (11.08) $ 0.74 $ 0.67 Fully diluted (11.08) 0.70 0.62 Cash flow from operations (1) $ 30,096 $ 56,607 $ 34,140 - ------------------------------------------------------------------------------------------------------- (1) Represents cash flow provided by operations, exclusive of the net change in non-cash working capital balances.
The following table summarizes the cash flow, DD&A and results of operations on a BOE basis for the comparative periods. Each of the individual components are discussed above.
Year Ended December 31, - --------------------------------------------------------------------------------------------------------- Per BOE Data 1998 1997 1996 - --------------------------------------------------------------------------------------------------------- Revenue $ 11.38 $ 16.75 $ 17.69 Production expenses (4.05) (4.36) (4.51) - --------------------------------------------------------------------------------------------------------- Production netback 7.33 12.39 13.18 General and administrative (1.02) (1.30) (1.50) Interest and other income (expense) (2.13) 0.02 (0.26) - --------------------------------------------------------------------------------------------------------- Cash flow from operations(a) 4.18 11.11 11.42 DD&A (7.26) (6.42) (5.99) Deferred income taxes 2.17 (1.75) (1.78) Writedown of oil and natural gas properties (38.93) - - Other non-cash items (0.09) (0.01) (0.72) - --------------------------------------------------------------------------------------------------------- Net income (loss) $ (39.93) $ 2.93 $ 2.93 - --------------------------------------------------------------------------------------------------------- (a) Represents cash flow provided by operations, exclusive of the net change in non-cash working capital balances.
Market Risk Management The Company uses fixed and variable rate debt to partially finance budgeted expenditures. These agreements expose the Company to market risk related to changes in interest rates. The Company does not hold or issue derivative financial instruments for trading purposes. The following table presents the carrying and fair value of the Company's debt along with average interest rates. Fair values are calculated as the net present value of the expected cash flows of the financial instrument.
Expected Maturity Dates (in thousands) 1999-2001 2002 2003-2007 2008 Total Fair Value - --------------------------------------------------------------------------------------------------------------------------- Variable Rate Debt: Bank Debt.......................... $ - $ 100,000 $ - $ - $ 100,000 $ 100,000 The average interest rate on the bank debt is 6.7%. Fixed Rate Debt: Subordinated Debt.................. - - - 125,000 125,000 110,000 The interest rate on the subordinated debt is a fixed rate of 9%.
-29- The Company also entered into various financial contracts to hedge its exposure to commodity price risk associated with anticipated future gas production. These contracts consist of price ceilings and floors (no-cost collars). These contracts in effect at December 31, 1998 run through December 2000. Gain or loss on these derivative commodity contracts would be offset by a corresponding gain or loss on the hedged commodity positions. Based on future market prices at December 31, 1998, the Company would not receive or pay any amounts under these commodity contracts. If futures market prices were to increase 10% from those in effect at December 31, 1998, the Company would be required to make cash payments under the commodity contracts of approximately $120,000. If futures market prices were to decline 10% from those in effect as December 31, 1998, the Company would receive cash payments under the commodity contacts of approximately $1.5 million. Year 2000 Issues Year 2000 issues relate to the ability of computer programs or equipment to accurately calculate, store or use dates after December 31, 1999. These dates can be handled or interpreted in a number of different ways, but the most common error is for the system to contain a two digit year which may cause the system to interpret the year 2000 as 1900. Errors of this type can result in system failures, miscalculations and the disruption of operations, including, among other things, a temporary inability to process transactions, send invoices or engage in similar normal business. In response to the Year 2000 issues, the Company has developed a strategic plan divided into the following phases: inventory, product compliance based on vendor representations and in-house testing, third party integration and development of a contingency plan. All of the Company's processing needs are handled by third party systems, none of which have been substantially modified and all of which have been purchased within the last few years. Therefore, the Company's initial review of its in-house systems with regard to Year 2000 issues required an inventory of its systems and a review of the vendor representations. The Company has completed this initial review of its information systems. The licensor of the Company's core financial software system has certified that such software is Year 2000 compliant. Additionally, most other less critical software systems, various types of equipment and non-information technology have been reviewed, and based on vendor representations, are either compliant, will be compliant with the next forthcoming software release or are systems that are not date specific. The Company's non-information technology consists primarily of various oil and gas exploration and production equipment. The initial review has established that the primary non-information technology systems functions are either not date sensitive or are Year 2000 compliant based on vendor representations, and are therefore predicted to operate in customary manners when faced with Year 2000 issues. However, the Company has determined that in the event such systems are unable to address the Year 2000, employees can manually perform most, if not all, functions. In anticipation of Year 2000 issues, the Company is also evaluating the Year 2000 readiness status of its third party service suppliers. In addition to reviewing Year 2000 readiness statements issued by the third parties handling the Company's processing needs, to date the Company has received, and is relying upon, Year 2000 readiness reports periodically issued by its financial services and electrical service providers, vendors and purchasers of the Company's oil and natural gas products. The Company is continuing to review Year 2000 readiness of third party service suppliers and, based on their representations, does not currently foresee material disruptions in the Company's business as a result of Year 2000 issues. Unanticipated prolonged losses of certain services, such as electrical power, could cause material disruptions for which no economically feasible contingency plan has been developed. The Company is continuing to conduct in-house testing of the core systems and non-information technology, and to date either all systems tested have adequately addressed possible Year 2000 scenarios or the Company has a plan in place to remedy the deficiency. The Company expects testing to be completed during the second quarter of 1999. After the completion of its Year 2000 review and testing, the Company will further develop a contingency plan as required, including replacing or upgrading by December 31, 1999 any system incapable of addressing the Year 2000. This final step is expected to be completed during the third quarter of 1999. -30- Although the effects of Year 2000 issues cannot be predicted with certainty, the Company believes that the potential impact, if any, of such events will, at most, require employees to manually complete otherwise automated tasks or calculations, other than those which might occur in a "worst case" scenario as described below, which the Company does not anticipate will occur. After considering Year 2000 effects on in-house operations, the Company does not expect that any additional training would be required to perform these tasks on a manual basis due to the level of experience of its personnel and the routine nature of the tasks being performed. If, based on the results of its in-house testing, the Company should determine that certain systems are not Year 2000 compliant and it appears as though the system is not likely to be compliant within a reasonable time period, the Company will either elect to perform the task manually or will attempt to purchase a different system for that particular task and convert before December 31, 1999. The Company does not believe that either option would impact the Company's ability to continue exploration, drilling, production or sales activities, although the tasks may require additional time and personnel to complete the same function or may require incremental time and personnel during 1999 for a conversion to a new system. The Company's core business consists primarily of oil and gas acquisition, development and exploration activities. The equipment which is deemed "mission critical" to the Company's activities requires external power sources such as electricity supplied by third parties. Although the Company maintains limited on-site secondary power sources such as generators, it is not economically feasible to maintain secondary power supplies for any major component of its "mission critical" equipment. Therefore, the most reasonably likely worst case Year 2000 scenario for the Company would involve a disruption of third party supplied electrical power, which would result in a substantial decrease in the Company's oil production. Such event could result in a business interruption that could materially affect the Company's operations, liquidity or capital resources. The Company has initiated the third party integration phase and will continue to have formal communications with its significant suppliers, business partners and key customers to determine the extent to which the Company is vulnerable to either the third parties' or its own failure to correct their Year 2000 issues. The Company has been communicating with such third parties to keep them informed of the Company's internal assessment of its Year 2000 review and plans. This portion of the review and discussions with third parties is expected to be completed during the second quarter of 1999. To date, approximately one-half of these third parties have provided certain favorable representations as to their Year 2000 readiness and received similar representations from the Company. There can be no guarantee that the systems of other companies on which the Company relies will be timely converted or that the conversion will be compatible with the Company's systems. However, after reviewing and estimating the effects of such events, the Company's contingency plan involves identifying and arranging for other vendors, purchasers and third party contractors to provide such services, if necessary, in order to maintain its normal operations. The Company has, and will continue to, utilize both internal and external resources to complete tasks and perform testing necessary to address the Year 2000 issue. The Company has not incurred, and does not anticipate that it will incur, any significant costs relating to the assessment and remediation of Year 2000 issues. -31- Forward-Looking Information The statements contained in this Annual Report on Form 10-K that are not historical facts, including, but not limited to, statements found in this Management's Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements, as that term is defined in Section 21E of the Securities and Exchange Act of 1934, as amended, that involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, capital expenditures, drilling activity, acquisition plans and proposals and dispositions, development activities, cost savings, production efforts and volumes, hydrocarbon reserves, hydrocarbon prices, liquidity, Year 2000 issues, regulatory matters and competition. Such forward-looking statements generally are accompanied by words such as "plan," "estimate," "expect," "predict," "anticipate," "projected," "should," "assume," "believe" or other words that convey the uncertainty of future events or outcomes. Such forward-looking information is based upon management's current plans, expectations, estimates and assumptions and is subject to a number of risks and uncertainties that could significantly affect current plans, anticipated actions, the timing of such actions and the Company's financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by or on behalf of the Company. Among the factors that could cause actual results to differ materially are: fluctuations of the prices received or demand for the Company's oil and natural gas, the uncertainty of drilling results and reserve estimates, operating hazards, acquisition risks, requirements for capital, general economic conditions, competition and government regulations, as well as the risks and uncertainties discussed in this annual report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in the Company's other public reports, filings and public statements. In assessing Year 2000 issues, the Company has relied on certain representations of third parties and has attempted to predict and address all possible scenarios which could arise. However, uncertainties exist which could cause Year 2000 effects to be more significant than the Company anticipates. Such uncertainties include the success of the Company in identifying systems and programs that are not Year 2000 compliant, the nature and amount of programming required to up-grade or replace each of the affected programs, the availability, rate and magnitude of related labor and consulting costs and the success of the Company's vendors in addressing the Year 2000 issue. Item 8. Financial Statements and Supplementary Data - --------------------------------------------------- The information required by Item 8 is set forth in the Independent Auditors' Report and Consolidated Financial Statements included herein following the signature page hereof. -32- SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Denbury Resources Inc. and Denbury Management, Inc. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. DENBURY RESOURCES INC. DENBURY MANAGEMENT, INC. March 18, 1999 /s/ Phil Rykhoek ------------------------------------------------ Phil Rykhoek Chief Financial Officer and Secretary March 18, 1999 /s/ Bobby J. Bishop ------------------------------------------------ Bobby J. Bishop Chief Accounting Officer and Controller Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of each respective company and in the capacities and on the dates indicated. March 18, 1999 /s/ Ronald G. Greene ------------------------------------------------ Ronald G. Greene Chairman of the Board and Director Denbury Resources Inc. March 18, 1999 /s/ Gareth Roberts ------------------------------------------------ Gareth Roberts Director, President and Chief Executive Officer (Principal Executive Officer) Denbury Resources Inc. March 18, 1999 /s/ Phil Rykhoek ------------------------------------------------ Phil Rykhoek Chief Financial Officer and Secretary (Principal Financial Officer) Denbury Resources Inc. -37- March 18, 1999 /s/ Bobby J. Bishop ------------------------------------------------ Bobby J. Bishop Chief Accounting Officer and Controller (Principal Accounting Officer) Denbury Resources Inc. March 18, 1999 /s/ Wilmot L. Matthews ------------------------------------------------ Wilmot L. Matthews Director Denbury Resources Inc. March 18, 1999 /s/ Wieland F. Wettstein ------------------------------------------------ Wieland F. Wettstein Director Denbury Resources Inc. March 18, 1999 /s/ Gareth Roberts ------------------------------------------------ Gareth Roberts Director, President and Chief Executive Officer (Principal Executive Officer) Denbury Management, Inc. March 8, 1999 /s/ Phil Rykhoek ------------------------------------------------ Phil Rykhoek Director, Chief Financial Officer and Secretary (Principal Financial Officer) Denbury Management, Inc. March 18, 1999 /s/ Bobby J. Bishop ------------------------------------------------ Bobby J. Bishop Chief Accounting Officer and Controller (Principal Accounting Officer) Denbury Management, Inc. March 18, 1999 /s/ Mark Worthey ------------------------------------------------ Mark Worthey Director and Vice President, Operations Denbury Management, Inc. -38- DENBURY RESOURCES INC. INDEX TO FINANCIAL STATEMENTS DECEMBER 31, 1998, 1997 AND 1996 FINANCIAL STATEMENTS Page ---- Independent Auditors' Report F-2 Consolidated Balance Sheets F-3 Consolidated Statements of Operations F-4 Consolidated Statements of Cash Flows F-5 Consolidated Statement of Changes in Shareholders' Equity (Deficit) F-6 Notes to the Consolidated Financial Statements F-7 thru F-29 FINANCIAL STATEMENT SCHEDULES OMITTED The financial statement schedules are omitted because they are not required to be filed in this amendment or because they are not applicable or the required information is shown in the consolidated financial statements or notes thereto. F - 1 Independent Auditors' Report To the Shareholders of Denbury Resources Inc. We have audited the consolidated balance sheets of Denbury Resources Inc. as at December 31, 1998 and 1997 and the consolidated statements of operations, changes in shareholders' equity (deficit) and cash flows for each of the years in the three year period ended December 31, 1998. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in Canada and the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. In our opinion, these consolidated financial statements present fairly in all material respects, the financial position of the Company as at December 31, 1998 and 1997 and the results of its operations and the changes in shareholders' equity (deficit) and cash flows for each of the years in the three year period ended December 31, 1998, in accordance with accounting principles generally accepted in Canada. Deloitte & Touche LLP Chartered Accountants Calgary, Alberta February 19, 1999 Note: See separate comments by auditors for U.S. Readers on Canada - U.S. Reporting Difference on page F-29. F - 2 CONSOLIDATED BALANCE SHEETS
AMOUNTS IN THOUSANDS OF U.S. DOLLARS DECEMBER 31, ------------------------------ 1998 1997 ------------- ------------- ASSETS CURRENT ASSETS Cash and cash equivalents........................................... $ 2,049 $ 9,326 Accrued production receivable....................................... 5,495 8,692 Trade and other receivables......................................... 16,390 15,362 ------------- ------------- Total current assets ..................................... 23,934 33,380 ------------- ------------- PROPERTY AND EQUIPMENT (USING FULL COST ACCOUNTING) Oil and natural gas properties...................................... 508,571 388,766 Unevaluated oil and natural gas properties.......................... 65,645 82,798 Less accumulated depletion and depreciation......................... (393,552) (62,732) ------------- ------------- Net property and equipment................................... 180,664 408,832 ------------- ------------- OTHER ASSETS........................................................... 8,261 5,336 ------------- ------------- TOTAL ASSETS................................................ $ 212,859 $ 447,548 ============= ============= LIABILITIES AND SHAREHOLDERS' EQUITY (DEFICIT) CURRENT LIABILITIES Accounts payable and accrued liabilities............................ $ 13,570 $ 24,616 Oil and gas production payable...................................... 5,118 6,052 Current portion of long-term debt .................................. - 20 ------------- ------------- Total current liabilities................................... 18,688 30,688 ------------- ------------- LONG-TERM LIABILITIES Long-term debt...................................................... 225,000 240,000 Provision for site reclamation costs................................ 1,436 1,017 Deferred income taxes and other..................................... - 15,620 ------------- ------------- Total long-term liabilities................................. 226,436 256,637 ------------- ------------- FINANCING REQUIREMENTS (NOTE 1) SHAREHOLDERS' EQUITY (DEFICIT) Common shares, no par value, unlimited shares authorized; outstanding - 26,801,680 and 20,388,683 shares at December 31, 1998 and December 31, 1997, respectively...................... 227,796 133,139 Retained earnings (accumulated deficit)............................. (260,061) 27,084 ------------- ------------- Total shareholders' equity (deficit)........................ (32,265) 160,223 ------------- ------------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY (DEFICIT)........ $ 212,859 $ 447,548 ============= =============
Approved by the Board: /s/ Gareth Roberts /s/ Wieland F. Wettstein - ------------------ ------------------------ Gareth Roberts Wieland F. Wettstein Director Director See Notes to Consolidated Financial Statements. F - 3 CONSOLIDATED STATEMENTS OF OPERATIONS
YEAR ENDED DECEMBER 31, ---------------------------------------- AMOUNTS IN THOUSANDS EXCEPT PER SHARE AMOUNTS (U.S. DOLLARS) 1998 1997 1996 ------------- ---------- ---------- REVENUES Oil, natural gas and related product sales.................. $ 81,883 $ 85,333 $ 52,880 Interest income and other................................... 1,623 1,123 769 ------------- ---------- ---------- Total revenues........................................ 83,506 86,456 53,649 ------------- ---------- ---------- EXPENSES Production.................................................. 29,162 22,218 13,495 General and administrative.................................. 6,556 6,182 4,267 Interest.................................................... 17,534 1,111 1,993 Imputed preferred dividends................................. - - 1,281 Loss on early extinguishment of debt........................ - - 440 Depletion and depreciation.................................. 52,234 32,719 17,904 Franchise taxes............................................. 785 428 213 Writedown of oil and natural gas properties................. 280,000 - - ------------- ---------- ---------- Total expenses....................................... 386,271 62,658 39,593 ------------- ---------- ---------- Income (loss) before income taxes................................ (302,765) 23,798 14,056 Income tax benefit (provision)................................... 15,620 (8,895) (5,312) ------------- ---------- ---------- NET INCOME (LOSS)................................................ $ (287,145) $ 14,903 $ 8,744 ============= ========== ========== NET INCOME (LOSS) PER COMMON SHARE............................... Basic....................................................... $ (11.08) $ 0.74 $ 0.67 Fully diluted............................................... $ (11.08) $ 0.70 $ 0.62 Average number of common shares outstanding...................... 25,926 20,224 13,104 ============= ========== ==========
See Notes to Consolidated Financial Statements F - 4 CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31, --------------------------------------- AMOUNTS IN THOUSANDS OF U.S. DOLLARS 1998 1997 1996 ------------ ----------- ----------- CASH FLOW FROM OPERATING ACTIVITIES: Net income (loss)........................................... $ (287,145) $ 14,903 $ 8,744 Adjustments needed to reconcile to net cash flow provided by operations: Depletion and depreciation.............................. 52,234 32,719 17,904 Writedown of oil and natural gas properties............. 280,000 - - Deferred income taxes................................... (15,620) 8,895 5,312 Imputed preferred dividend.............................. - - 1,281 Loss on early extinguishment of debt.................... - - 440 Other................................................... 627 90 459 ------------ ----------- ----------- 30,096 56,607 34,140 Changes in working capital items relating to operations: Accrued production receivable........................... 3,197 3,214 (8,694) Trade and other receivables............................. (1,028) (11,719) (1,508) Accounts payable and accrued liabilities................ (11,046) 13,713 6,711 Oil and gas production payable.......................... (934) 502 4,536 ------------ ----------- ----------- NET CASH FLOW PROVIDED BY OPERATIONS........................... 20,285 62,317 35,185 ------------ ----------- ----------- CASH FLOW USED FOR INVESTING ACTIVITIES: Oil and natural gas expenditures........................ (88,978) (81,282) (38,450) Acquisition of oil and natural gas properties........... (13,674) (224,145) (48,407) Net purchases of other assets........................... (1,145) (2,132) (1,726) Acquisition of subsidiary, net of cash acquired......... - - 209 ------------ ----------- ----------- NET CASH USED FOR INVESTING ACTIVITIES......................... (103,797) (307,559) (88,374) ------------ ----------- ----------- CASH FLOW FROM FINANCING ACTIVITIES: Bank repayments......................................... (200,000) - (47,900) Bank borrowings......................................... 60,000 239,900 47,900 Issuance of subordinated debt........................... 125,000 - - Issuance of common stock................................ 94,657 2,816 60,664 Costs of debt financing................................. (3,402) (1,511) (411) Other................................................... (20) (90) (164) ------------ ----------- ----------- NET CASH PROVIDED BY FINANCING ACTIVITIES...................... 76,235 241,115 60,089 ------------ ----------- ----------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........... (7,277) (4,127) 6,900 Cash and cash equivalents at beginning of year................. 9,326 13,453 6,553 ------------ ----------- ----------- CASH AND CASH EQUIVALENTS AT END OF YEAR....................... $ 2,049 $ 9,326 $ 13,453 ============ =========== =========== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the year for interest.................. $ 11,821 $ 447 $ 1,621 SUPPLEMENTAL DISCLOSURE OF FINANCING ACTIVITIES: Conversion of subordinated debt to common stock......... - - $ 3,314 Conversion of preferred stock to common stock........... - - 16,281 Assumption of liabilities in acquisition................ - - 1,321
See Notes to Consolidated Financial Statements F - 5 CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY (DEFICIT)
RETAINED EARNINGS COMMON SHARES (ACCUMULATED (NO PAR VALUE) DEFICIT) TOTAL --------------------------- ---------------- ------------- Dollar Amounts in Thousands of U.S. Dollars Shares Amounts ------------- ----------- BALANCE - JANUARY 1, 1996 11,428,809 $ 50,064 $ 3,437 $ 53,501 ------------- ----------- ---------------- ------------- Issued pursuant to employee stock option plan...... 197,675 1,070 - 1,070 Issued pursuant to employee stock purchase plan.... 31,311 358 - 358 Public placement of common shares.................. 4,940,000 58,776 - 58,776 Conversion of preferred stock...................... 2,816,372 16,281 - 16,281 Conversion of warrants............................. 75,000 460 - 460 Conversion of subordinated debt.................... 566,590 3,314 - 3,314 Net income......................................... - - 8,744 8,744 ------------- ----------- ---------------- ------------- BALANCE - DECEMBER 31, 1996 20,055,757 130,323 12,181 142,504 ------------- ----------- ---------------- ------------- Issued pursuant to employee stock option plan...... 280,656 1,916 - 1,916 Issued pursuant to employee stock purchase plan.... 52,270 900 - 900 Net income......................................... - - 14,903 14,903 ------------- ----------- ---------------- ------------- BALANCE - DECEMBER 31, 1997 20,388,683 133,139 27,084 160,223 ------------- ----------- ---------------- ------------- Issued pursuant to employee stock option plan...... 132,256 954 - 954 Issued pursuant to employee stock purchase plan.... 101,561 1,139 - 1,139 Conversion of warrants............................. 625,000 4,625 - 4,625 Public placement of common shares.................. 5,554,180 87,939 - 87,939 Net loss........................................... - - (287,145) (287,145) ------------- ----------- ---------------- ------------- BALANCE - DECEMBER 31, 1998 26,801,680 $ 227,796 $ (260,061) $ (32,265) ============= =========== ================ =============
See Notes to Consolidated Financial Statements F - 6 Notes to Consolidated Financial Statements Years Ended December 31, 1998, 1997 and 1996 NOTE 1. BASIS OF PRESENTATION AND FINANCING REQUIREMENTS The consolidated financial statements have been presented using accounting principles applicable to a going concern, which assumes that the Company will continue operations in the foreseeable future and be able to realize assets and satisfy liabilities in the normal course of business. As of December 31, 1998, the current value of the Company's reserves, using the unescalated 1998 year-end oil and natural gas prices and costs, are insufficient to repay the senior bank loan, the 9% Senior Subordinated Notes due 2008 and the related interest costs, which casts substantial doubt upon the validity of the going concern assumption. The Company's ability to continue as a going concern is dependent upon the completion of the sale of stock to the Texas Pacific Group ("TPG") as described in Note 6 or an increase in oil and natural gas prices. Although the Company believes, based upon all the factors known to management at this time, that the stock sale will be approved by shareholders and thus will occur, if this proposed sale of stock does not close or oil and natural gas prices do not increase to enable the repayment of the debt and interest costs, the Company will be in default of covenants of its bank credit agreement. If this default were to cause its banks to significantly reduce the borrowing base under its credit agreement or accelerate the loan, the Company would not have sufficient liquid assets to immediately repay or substantially reduce the loan. In this event, the Company would attempt to negotiate an accommodation with the bank, which cannot be assured, and might be required to sell some of its properties to repay the loan. If the borrowing base is not reduced and the loan is not accelerated and based on current product prices and production levels, the Company believes it would have sufficient cash flow from operations to meet its obligations and continue operations during 1999, provided that the Company further reduces its capital expenditures to a level equal to cash flow; however, this reduction in expenditures makes it unlikely that the Company would be able to maintain positive cash flow beyond 1999, as production would be expected to decline over time. If the going concern assumption were not appropriate for these financial statements, then significant adjustments would be necessary in the carrying value of assets and liabilities, the reported net loss and the balance sheet classifications. NOTE 2. SIGNIFICANT ACCOUNTING POLICIES The Company operated in only one business segment as its operating activities are related to exploration, development and production of oil and natural gas in the United States. On October 9, 1996 the shareholders of the Company approved an amendment to the Articles of Continuance to consolidate the number of issued and outstanding Common Shares on the basis of one Common Share for each two Common Shares outstanding. All applicable shares and per share data have been adjusted for the reverse stock split. Principles of Consolidation The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles and include the accounts of the Company and its wholly owned subsidiaries, Denbury Holdings Ltd., Denbury Management, Inc, Denbury Marine L.L.C. and Denbury Energy Services ("DES"). Prior to May 1, 1996, the Company owned 50% of DES and consolidated only its equity ownership. Denbury Holdings Ltd. was merged into Denbury Resources Inc. in December 1997. All material intercompany balances and transactions have been eliminated. Oil and Natural Gas Operations A) CAPITALIZED COSTS The Company follows the full-cost method of accounting for oil and natural gas properties. Under this method, all costs related to acquisitions, exploration and development of oil and natural gas reserves are capitalized and accumulated in a single cost center representing the Company's activities undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical F - 7 Notes to Consolidated Financial Statements Years Ended December 31, 1998, 1997 and 1996 expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells and general and administrative expenses directly related to exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. Proceeds received from disposals are credited against accumulated costs except when the sale represents a significant disposal of reserves in which case a gain or loss is recognized. B) DEPLETION AND DEPRECIATION The costs capitalized, including production equipment, are depleted or depreciated on the unit-of-production method, based on proved oil and natural gas reserves as determined by independent petroleum engineers. Oil and natural gas reserves are converted to equivalent units based upon the relative energy content which is six thousand cubic feet of natural gas to one barrel of crude oil. C) SITE RECLAMATION Estimated future costs of well abandonment and site reclamation, including the removal of production facilities at the end of their useful life, are provided for on a unit-of-production basis. Costs are based on engineering estimates of the anticipated method and extent of site restoration, valued at year-end prices, net of estimated salvage value, and in accordance with the current legislation and industry practice. The annual provision for future site reclamation costs is included in depletion and depreciation expense. D) CEILING TEST The capitalized costs less accumulated depletion and depreciation, related deferred taxes and site reclamation costs are limited to an amount which is not greater than the estimated future net revenue from proved reserves using unescalated period-end prices less estimated future site restoration and abandonment costs, future production-related general and administrative expenses, financing costs and income taxes, plus the cost (net of impairments) of undeveloped properties. E) JOINT INTEREST OPERATIONS Substantially all of the Company's oil and natural gas exploration and production activities are conducted jointly with others. These financial statements reflect only the Company's proportionate interest in such activities and any amounts due from other partners are included in the trade receivables. Foreign Currency Translation In that virtually all of the Company's assets have been located in the United States since 1993 when the Company sold its Canadian oil and natural gas properties, the United States assets and operations are accounted for and reported in U.S. dollars and no translation is necessary. The minor amount of Canadian assets and liabilities is translated to U.S. dollars using year-end exchange rates and any Canadian operations, which are principally minor administrative and interest expenses, are translated using the historical exchange rate. Earnings per Share Net income or loss per common share is computed by dividing the net income or loss attributable to common shareholders by the weighted average number of shares of common shares outstanding. In accordance with Canadian generally accepted accounting principles ("GAAP"), the imputed dividend during 1996 on the Convertible First Preferred Shares, Series A has been recorded as an operating expense in the accompanying financial statements and this is deducted from net income in computing earnings per share. The conversion of the Convertible First Preferred Shares, Series A ("Convertible Preferred") was anti-dilutive and was not included in the calculation of earnings per share. In computing fully diluted earnings per share, the stock options, warrants F - 8 Notes to Consolidated Financial Statements Years Ended December 31, 1998, 1997 and 1996 and convertible debt instruments were dilutive for the years ended December 31, 1997 and 1996 and were assumed to be converted or exercised as of the beginning of the respective period with the proceeds used to reduce interest expense. As a result of the net loss for the year ended December 31, 1998, these instruments were anti-dilutive. All of the Convertible Preferred and the convertible debt were converted into common shares during 1996 and thus were not relevant to the calculation of earnings per share after 1996. Statement of Cash Flows For purposes of the Statement of Cash Flows, cash equivalents include time deposits, certificates of deposit and all liquid debt instruments with maturities at the date of purchase of three months or less. Revenue Recognition Revenue is recognized at the time oil and natural gas is produced and sold. Any amounts due from purchasers of oil and natural gas are included in accrued production receivables. The Company follows the "sales method" of accounting for its oil and natural gas revenue whereby the Company recognizes sales revenue on all oil or natural gas sold to its purchasers, regardless of whether the sales are proportionate to the Company's ownership in the property. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. As of December 31, 1998 and 1997 the Company's aggregate oil and natural gas imbalances were not material to its consolidated financial statements. The Company recognizes revenue and expenses of purchased producing properties commencing from the closing or agreement date, at which time the Company also assumes control. Income Taxes Income taxes are accounted for using the liability method under which deferred income taxes are recognized for the tax consequences of "temporary differences" by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. During 1997, this liability method for computing income taxes was adopted as GAAP in Canada. This change to the liability method from the deferral method did not have a material impact on the Company's financial statements. Financial Instruments with Off-balance Sheet Risk and Concentrations of Credit Risk The Company's product price hedging activities are described in Note 7 to the consolidated financial statements. The Company enters into financial transactions to hedge anticipated future production. Hedge accounting is utilized when there is a high degree of correlation between price movements in the derivative and the underlying item designated as being hedged. The impact of changes in the market value of the financial transactions, which serve as hedges, is deferred until the related physical transaction is completed. The changes, when recognized, are included in oil and gas revenues. If a financial transaction that has been accounted for as a hedge is closed before F - 9 Notes to Consolidated Financial Statements Years Ended December 31, 1998, 1997 and 1996 the date of the anticipated future transaction, the accumulated change in the value of the financial transactions is deferred until the related physical transaction is completed. In the event it becomes likely that an anticipated transaction will not occur or that adequate correlation no longer exists, hedge accounting is terminated and future changes in the fair value of the derivative are recognized as gains or losses in the statement of operations. Credit risk relating to these hedges is minimal because of the credit risk standards required for counter-parties and monthly settlements. The Company has entered into hedging contracts with only large and financially strong companies. The Company's financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents, short-term investments and trade and accrued production receivables in addition to the product price hedges discussed above. The Company's cash equivalents and short-term investments represent high-quality securities placed with various investment grade institutions. This investment practice limits the Company's exposure to concentrations of credit risk. The Company's trade and accrued production receivables are dispersed among various customers and purchasers; therefore, concentrations of credit risk are limited. Also, the Company's more significant purchasers are large companies with excellent credit ratings. If customers are considered a credit risk, letters of credit are the primary security obtained to support lines of credit. Fair Value of Financial Instruments As of December 31, 1998 and 1997, the carrying value of the Company's bank debt and most other financial instruments approximates their fair market value. The Company's bank debt is based on a floating interest rate and thus adjusts to market as interest rates change. During 1998, the Company issued $125 million of 9% Senior Subordinated Notes due 2008. As of December 31, 1998, these notes had a market value of approximately $110 million based on recent trading levels of the notes. Based on market prices as of December 31, 1998, the Company's open product price hedging contracts (See Note 7) have no deferred gain or loss. The Company's other financial instruments are primarily cash, cash equivalents, short-term receivables and payables which approximate fair value due to the nature of the instrument and the relatively short maturities. Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amount of certain assets, liabilities, revenues and expenses as of and for the reporting period. Estimates and assumptions are also required in the disclosure of contingent assets and liabilities as of the date of the financial statements. Actual results may differ from such estimates. F - 10 Notes to Consolidated Financial Statements Years Ended December 31, 1998, 1997 and 1996 NOTE 3. PROPERTY AND EQUIPMENT Unevaluated Oil and Natural Gas Properties Excluded From Depletion Under full cost accounting, the Company may exclude certain unevaluated costs from the amortization base pending determination of whether proved reserves have been discovered or impairment has occurred. A summary of the unevaluated properties excluded from oil and natural gas properties being amortized at December 31, 1998 and 1997 and the year in which they were incurred follows:
DECEMBER 31, 1998 DECEMBER 31, 1997 ------------------------------------ --------------------------------------- Costs Incurred During: Costs Incurred During: ------------------------- ------------------------- 1998 1997 Total 1997 1996 Total ------------ ----------- ---------- ------------ ----------- ---------- AMOUNTS IN THOUSANDS Property acquisition costs $ 4,693 $ 48,896 $ 53,589 $ 77,238 $ 286 $ 77,524 Exploration costs......... 8,260 3,796 12,056 3,817 1,457 5,274 ------------ ----------- ---------- ------------ ----------- ---------- Total................. $ 12,953 $ 52,692 $ 65,645 $ 81,055 $ 1,743 $ 82,798 ============ =========== ========== ============ =========== ==========
Costs are transferred into the amortization base on an ongoing basis as the projects are evaluated and proved reserves established or impairment determined. Pending determination of proved reserves attributable to the above costs, the Company cannot assess the future impact on the amortization rate. Full Cost Ceiling Test During the first quarter of 1998, the Company excluded the Heidelberg Field acquired late in 1997 from the full cost ceiling test because the Company believed, based on its success with similar properties in Mississippi, that the value of this property was at least equal to its carrying cost. Had this property been included in the ceiling test calculation as of March 31, 1998, the Company would have had a writedown of the property carrying costs of approximately $35 million for both U.S. and Canadian GAAP. During the second quarter of 1998, oil prices continued to decline, with a drop of approximately $1.50 in the NYMEX oil price from March 31 to June 30, 1998. Furthermore, the gap between the NYMEX oil price and the net realized price widened, causing the net realized price at Heidelberg Field to drop approximately $1.00 per Bbl more than the decline in the NYMEX price. Due to the continued low oil prices, in June 1998 the Company announced that it was reducing its drilling activity and capital expenditure budget on its oil properties, including Heidelberg Field, until oil product prices recover. As a result of this curtailment, it was unlikely that the proved reserves and production from this property would increase as quickly as originally anticipated, thus causing a decline in the current value of this property. Therefore, as of June 30, 1998, the Company included the Heidelberg Field in the full cost pool for its ceiling test, which coupled with the reduction in oil prices, resulted in a $165 million writedown of the full cost pool as of that date. This writedown was approximately the same for both U.S. and Canadian GAAP and was computed using June 30, 1998 prices, which were equivalent to a NYMEX oil price of $14.00 per Bbl and an average net realized oil price of $8.90 per Bbl, a drop of approximately $5.92 per Bbl from the net prices used in the December 31, 1997 reserve report. As of December 31, 1998, oil prices had deteriorated further to a NYMEX price of approximately $12.00 per Bbl and an average net realized price of $7.37 per Bbl. As a result of this further decrease in price, coupled with some downward revisions in the proven reserves, the Company recognized an additional ceiling test writedown as of December 31, 1998. As it is expected by management that the prices realized over the remaining life of the reserves will be higher than the year-end prices, an average NYMEX oil price of $14.00 per Bbl (a price slightly less than the 1998 average price) was used in determining the ceiling test at year-end. Based on this $14.00 NYMEX price and using undiscounted future net revenues after considering the effects of administrative and F - 11 Notes to Consolidated Financial Statements Years Ended December 31, 1998, 1997 and 1996 interest costs, an additional writedown of $115 million was recognized for the fourth quarter, for a total writedown for the year of $280 million. This writedown is the same as that required under U.S. GAAP using the year-end $12.00 NYMEX price and the net present value of the reserves without consideration of administrative and interest costs. Under Canadian GAAP, if one were to use the unescalated reserve forecast using year-end prices, the full $115.0 million remaining balance of the oil and natural gas properties would be written off. Capitalized Costs General and administrative costs that directly relate to exploration and development activities that were capitalized during the period totaled $2,657,000, $2,225,000 and $1,224,000 for the years ended December 31, 1998, 1997 and 1996, respectively. Amortization per BOE, excluding the full cost pool writedown, was $7.26, $6.42 and $5.99 for the years ended December 31, 1998, 1997 and 1996, respectively. NOTE 4. NOTES PAYABLE AND LONG-TERM INDEBTEDNESS DECEMBER 31, ---------------------------- 1998 1997 ------------ ------------ AMOUNTS IN THOUSANDS Senior bank loan...................................$ 100,000 $ 240,000 9% Senior Subordinated Notes due 2008.............. 125,000 - Other notes payable................................ - 20 ------------ ------------ 225,000 240,020 Less portion due within one year................... - (20) ------------ ------------ Total long-term debt......................$ 225,000 $ 240,000 ============ ============ Banks The Company has a credit facility with Bank of America, as agent and part of a group of eight other banks. The credit facility was increased in size from $150 million to $300 million in December 1997 and the borrowing base was increased to $260 million in order to fund the property acquisition from Chevron. The December 31, 1997 outstanding balance of $240 million was reduced to $40 million as of February 26, 1998 after application of the net proceeds from the 1998 debt and equity offerings net of $9.8 million of additional borrowings. The credit facility consists of a five-year revolving credit facility and after the debt and equity offerings completed in February 1998 had a borrowing base of $165 million. This borrowing base is subject to review every six months and was reduced to $130 million at the October 1, 1998 redetermination date as a result of the low product prices. F - 12 Notes to Consolidated Financial Statements Years Ended December 31, 1998, 1997 and 1996 On February 19, 1999, the Company completed an amendment to its credit facility. This amendment set the borrowing base at $110 million, of which $60 million was considered to be conforming to the bank's normal credit policies. As a result of the writedown of oil and gas properties the Company was in default under its bank loan agreement as of December 31, 1998. The amendment modified the debt covenant such that the Company is now in compliance. This amendment also: o provides certain relief on the minimum equity and interest coverage tests; o changes the facility to one secured by substantially all of the Company's oil and natural gas properties; o requires that as long as the borrowing base is larger than the conforming borrowing base, that at least 75% of the funds borrowed under the facility subsequent to the closing of the proposed TPG purchase be used for either qualifying acquisitions or capital expenditures made to maintain, enhance or develop its proved reserves; o increases the interest rate to a range from LIBOR plus 1.0% to LIBOR plus 1.75% depending on amounts outstanding and LIBOR plus 2.125% if the outstanding debt exceeds the conforming borrowing base, currently set at $60 million; and o provides that a failure to close the sale of stock to TPG before June 16, 1999 would be an event of default. This credit facility has several restrictions including, among others: (i) a prohibition on the payment of dividends, (ii) a requirement for a minimum equity balance, (iii) a requirement to maintain positive working capital, as defined, (iv) a minimum interest coverage test and (v) a prohibition of most debt and corporate guarantees. As of December 31, 1998, the Company had $100 million outstanding on this line of credit and $370,000 of letters of credit outstanding. The next scheduled re-determination of the borrowing base will be as of October 1, 1999, based on June 30, 1999 assets and proved reserves. Subordinated Debt During 1996, the Company converted all of its previously issued convertible debentures with a total principal amount of Cdn. $4.5 million into 566,590 Common Shares. On February 26, 1998, Denbury Management Inc., a wholly-owned subsidiary of the Company, issued $125 million in aggregate principal amount of 9% Senior Subordinated Notes Due 2008 which require semi-annual interest payments only until maturity. These notes contain certain debt covenants, including covenants that limit (i) indebtedness, (ii) certain restricted payments including dividends, (iii) sale/leaseback transactions, (iv) transactions with affiliates, (v) liens, (vi) asset sales and (vii) mergers and consolidations. The net proceeds to the Company from the debt offering were approximately $121.8 million, before offering expenses. F - 13 Notes to Consolidated Financial Statements Years Ended December 31, 1998, 1997 and 1996 Indebtedness Repayment Schedule The Company's indebtedness as of December 31, 1998 is repayable as follows: AMOUNTS IN THOUSANDS - --------------------------------------------------------------- YEAR 1999 ........................................$ - 2000 ........................................ - 2001 ........................................ - 2002 ........................................ 100,000 Thereafter..................................... 125,000 ---------------- Total indebtedness $ 225,000 ================ NOTE 5. INCOME TAXES The Company's income tax provision is as follows:
YEAR ENDED DECEMBER 31, --------------------------------------- AMOUNTS IN THOUSANDS 1998 1997 1996 ----------- --------- ---------- Deferred Federal.........................................$ (15,620) $ 8,589 $ 5,312 State........................................... - 306 - ----------- --------- ---------- Total income tax provision (benefit)...............$ (15,620) $ 8,895 $ 5,312 =========== ========= ==========
Income tax expense for the year varies from the amount that would result from applying Canadian federal and provincial tax rates to income before income taxes as follows:
YEAR ENDED DECEMBER 31, ------------------------------------ AMOUNTS IN THOUSANDS 1998 1997 1996 ------------ ---------- ---------- Deferred income tax provision (benefit) calculated using the Canadian federal and provincial statutory combined tax rate of 44.34%......................... $ (134,245) $ 10,552 $ 6,233 Increase resulting from: Imputed preferred dividend.......................... - - 568 Non-deductible Canadian expenses.................... - - 97 Decrease resulting from: Valuation allowance................................. 96,402 - - Effect of lower income tax rates on United States income........................................... 22,223 (1,657) (1,586) ------------ ---------- ---------- Total income tax provision (benefit) $ (15,620) $ 8,895 $ 5,312 ============ ========== ==========
As a result of the net pre-tax loss of $302.8 million for the year ended December 31, 1998, an income tax provision for 1998 using the effective tax rate of 37% would have resulted in a $96.4 million deferred tax asset. Since the Company currently has a large tax net operating loss, it was uncertain whether this total tax asset could ultimately be realized, particularly in light of the low oil and natural gas prices. As such, the Company fully impaired the deferred tax asset, resulting in a 5% effective tax benefit rate for the year. F - 14 Notes to Consolidated Financial Statements Years Ended December 31, 1998, 1997 and 1996 The Company at December 31, 1998 had net operating loss carryforwards for U.S. federal income tax purposes of approximately $135.0 million and approximately $46.8 million for alternative minimum tax purposes. The net operating losses are scheduled to expire as follows: INCOME ALTERNATIVE AMOUNTS IN THOUSANDS TAX MINIMUM TAX - ----------------------------------------------------- --------------- YEAR 2004 .................................$ 39 $ - 2005 ................................. 11 - 2006 ................................. 644 500 2007 ................................. 714 99 2008 ................................. 5,016 4,889 2009 ................................. 3,377 2,868 2010 ................................. 3,467 3,420 2011 ................................. 5,061 1,115 2012 ................................. 29,508 4,124 2018 ................................. 87,212 29,775 Deferred income taxes relate to temporary differences based on tax laws and statutory rates in effect at the December 31, 1998 and 1997 balance sheet dates. At December 31, 1998 and 1997, all deferred tax assets and liabilities were computed based on Canadian GAAP amounts and were noncurrent as follows: DECEMBER 31, ---------------------------- AMOUNTS IN THOUSANDS 1998 1997 ------------- ------------ Deferred tax assets: Loss carryforwards....................... $ 49,968 $ 15,699 Basis difference of exploration and production assets.................... 46,888 (31,319) Deferred tax liabilities: Other.................................... (454) - ------------- ------------ Net deferred tax asset (liability)............. 96,402 (15,620) Less: Valuation allowance................ (96,402) - ------------- ------------ Total deferred tax asset (liability). $ - $ (15,620) ============= ============ NOTE 6. SHAREHOLDERS' EQUITY Authorized The Company is authorized to issue an unlimited number of Common Shares with no par value, First Preferred Shares and Second Preferred Shares. The preferred shares may be issued in one or more series with rights and conditions as determined by the Directors. Common Stock Each Common Share entitles the holder thereof to one vote on all matters on which holders are permitted to vote. No stockholder has any right to convert Common Shares into other securities. The holders of shares of common stock are entitled to dividends when and if declared by the Board of Directors from funds legally available F - 15 Notes to Consolidated Financial Statements Years Ended December 31, 1998, 1997 and 1996 therefore and, upon liquidation, to a pro rata share in any distribution to stockholders, subject to prior rights of the holders of the preferred stock. The Company is restricted from declaring or paying any cash dividend on the Common Shares by its bank loan agreement. Proposed Sale of Stock to the Texas Pacific Group On December 16, 1998, the Company entered into a stock purchase agreement with its largest shareholder, the Texas Pacific Group ("TPG"). This agreement provides for TPG to purchase 18,552,876 common shares of the Company at $5.39 per share for an aggregate consideration of $100 million. The consummation of this stock sale is conditioned upon the approval of the sale by the shareholders of the Company, completion of an amendment to the Company's bank agreement, the absence of a material adverse change, as that term is defined in the agreement, plus satisfaction of other conditions. The Company completed an amendment to its bank credit facility as of February 19, 1999 (see Note 4. Notes Payable and Long-Term Indebtedness - Banks) and is seeking shareholder approval at a special meeting of the shareholders currently expected to be held in April 1999. As a result of this sale of stock, TPG will gain control of the Company with ownership that will increase from approximately 32% to approximately 60%. Although the Company does not expect this transaction to result in any immediate changes to its directors, management or operations, TPG will have adequate voting power to control the election of directors, to determine the corporate and management policies of the Company and to effect the shareholder approval of a merger, consolidation or sale of all or substantially all of the assets of the Company. The Company expects to close this stock sale in April 1999 and plans to pursue acquisitions with funds made available under its bank credit facility as a result of the sale. Although the Company believes, based upon all the factors known to management at this time, that the stock sale will be approved by shareholders and thus will occur, if this proposed sale of stock does not close by June 16, 1999, the Company will be in default of its bank credit agreement. 1998 Equity Offering On February 26, 1998, the Company closed on a public offering of 5,240,780 Common Shares at a price to the public of $16.75 per share and a net price to the Company of $15.955 per share (the "Equity Offering"). Concurrently with the Equity Offering, TPG, the Company's largest shareholder, purchased 313,400 Common Shares from the Company at $15.955 per share, equal to the price to the public per share less underwriting discounts and commissions (the "TPG Purchase"). The net proceeds to the Company from the Equity Offering and TPG Purchase was approximately $88.6 million, before offering expenses. 1996 Capital Adjustments During 1996, the Company issued 250,000 Common Shares for the conversion of the 6 3/4% Convertible Debentures of the Company and 75,000 Common Shares for the exercise of half of the Cdn. $8.40 Warrants ("Warrants"). On October 10, 1996, the Company effected a one-for-two reverse split of its outstanding Common Shares. Effective October 15, 1996, all of the Company's outstanding 9 1/2% Convertible Debentures ("Debentures") were converted into 316,590 Common Shares. The Company also converted all of the 1,500,000 shares of Convertible Preferred on October 30, 1996 into 2,816,372 Common Shares. On October 30, 1996 and November 1, 1996, the Company also issued an aggregate of 4,940,000 Common Shares at a net price of $12.035 per share as part of a public offering for net proceeds to the Company of approximately $58.8 million. TPG purchased 800,000 of these shares at $12.035 per share. F - 15 Notes to Consolidated Financial Statements Years Ended December 31, 1998, 1997 and 1996 Warrants At December 31, 1998, 75,000 warrants were outstanding at an exercise price of Cdn. $8.40 expiring on May 5, 2000. Each warrant entitles the holder thereof to purchase one Common Share at any time prior to the expiration date. Stock Option Plan The Company maintains a Stock Option Plan which authorizes the grant of options up to 4,535,000 Common Shares, of which 2,015,756 options are subject to shareholder approval at a special meeting of the shareholders anticipated to be held in April, 1999. Under the terms of the plan, incentive and non-qualified options may be issued to officers, key employees and consultants. Options generally become exercisable over a four year vesting period with the specific terms of vesting determined by the Board of Directors at the time of grant. The options expire over terms not to exceed ten years from the date of grant, ninety days after termination of employment or permanent disability or one year after the death of the optionee. The options are granted at the fair market value at the time of grant which is generally defined as the average closing price of the Company's Common Shares for the ten trading days prior to issuance. The plan is administered by the Stock Option Committee of the Board. Following is a summary of stock option activity during the years ended December 31, 1998, 1997 and 1996:
YEAR ENDED DECEMBER 31, ---------------------------------------------------------------------------------- 1998 1997 1996 --------------------------- ---------------------------- ------------------------ Weighted Weighted Weighted Number Average Price Number Average Price Number Average Price ----------- ------------- ----------- -------------- ----------- -------------- Outstanding at beginning of year......................... 1,546,256 $ 11.06 1,053,000 $ 7.63 731,925 $ 6.11 Granted........................ 488,559 17.71 797,162 14.13 525,500 8.96 Terminated..................... (4,528) 17.25 (23,250) 11.51 (6,750) 6.28 Exercised...................... (132,256) 7.29 (280,656) 6.95 (197,675) 5.42 Expired........................ (7,500) 7.15 - - - $ - ----------- ------------- ----------- -------------- ----------- -------------- Outstanding at end of year..... 1,890,531 $ 13.04 1,546,256 $ 11.06 1,053,000 7.63 =========== ============= =========== ============== =========== ============== Options exercisable at end of year......................... 398,474 $ 8.85 391,872 $ 7.57 532,375 $ 6.82 =========== ============= =========== ============== =========== ==============
Weighted Weighted Options Outstanding as of Options Average Weighted Average Exercisable Average December 31, 1998: Outstanding Price Remaining Life (yrs.) Options Price - --------------------------------- ------------ ---------- ----------------------- ------------ ---------- Exercise price of: $4.71 to $7.00 350,700 $ 6.38 5.5 171,950 $ 5.87 $7.01 to $13.37 298,048 9.95 7.5 195,313 9.97 $13.38 to $17.37 775,715 13.84 8.2 19,550 16.01 $17.38 to $22.24 466,068 18.71 9.0 11,661 22.01
The Company also issued 1,627,988 stock options to all Company employees on January 4, 1999 in accordance with the terms of the plan. These options are subject to shareholder approval at a special meeting of shareholders anticipated to be held in April 1999. In 1995, the United States Financial Accounting Standards Board issued Statement of Financial Accounting F - 17 Notes to Consolidated Financial Statements Years Ended December 31, 1998, 1997 and 1996 Standards ("SFAS") No. 123, "Accounting for Stock-Based Compensation." With regard to its stock option plan, the Company applies APB Opinion No. 25 as allowed under SFAS 123 in accounting for this plan and accordingly no compensation cost has been recognized. Had compensation expense been determined based on the fair value at the grant dates for the stock option grants consistent with the method of SFAS No. 123, the Company's net income (loss) and net income (loss) per common share would have been reduced (increased) to the following pro forma amounts:
YEAR ENDED DECEMBER 31, ------------------------------------- 1998 1997 1996 ----------- ---------- -------- NET INCOME (LOSS): As reported (thousands)................................................$ (287,145) $ 14,903 $ 8,744 Pro forma (thousands).................................................. (289,463) 14,130 8,215 NET INCOME (LOSS) PER COMMON SHARE: As reported: Basic.......................................................$ (11.08) $ 0.74 $ 0.67 Fully diluted............................................... (11.08) 0.70 0.62 Pro forma: Basic.......................................................$ (11.16) $ 0.70 $ 0.63 Fully diluted............................................... (11.16) 0.66 0.59 Stock options issued during period (thousands)............................ 489 797 526 Weighted average exercise price...........................................$ 17.71 $ 14.13 $ 8.96 Average per option compensation value of options granted (a).............. 7.64 4.02 2.95 Compensation cost (thousands)............................................. 2,318 1,227 801 (a) Calculated in accordance with the Black-Scholes option pricing model, using the following assumptions: expected volatility computed using, as of the date of grant, the prior three-year monthly average of the Common Shares as listed on the TSE, which ranged from 38% to 63%; expected dividend yield - 0%; expected option term - 5 years; and risk-free rate of return as of the date of grant which ranged from 4.5% to 5.7%, based on the yield of five-year U.S. treasury securities.
Stock Purchase Plan In February 1996, the Company implemented a Stock Purchase Plan which authorizes the sale of Common Shares to all full-time employees. The number of Common Shares currently approved by the Board of Directors for this purpose is 750,000 shares of which 500,000 is subject to shareholder approval at a special meeting of shareholders anticipated to be held in April 1999. Under the plan, the employees may contribute up to 10% of their base salary and the Company matches 75% of the employee contribution. The combined funds are used to purchase previously unissued Common Shares of the Company based on its current market value at the end of each quarter. The Company recognizes compensation expense for the 75% Company matching portion, which totaled $648,000, $383,000 and $147,000 for the years ended December 31, 1998, 1997 and 1996, respectively. This plan is administered by the Stock Purchase Plan Committee of the Board. 401(k) Plan The Company offers a 401(k) Plan to which employees may contribute tax deferred earnings subject to Internal Revenue Service limitations. The Company matches 50% of employee contributions up to an employee contribution of 6% of their salary. This Company match becomes vested over a six year period. During 1998, the Company contributed $217,000 to the 401(k) Plan. F - 18 Notes to Consolidated Financial Statements Years Ended December 31, 1998, 1997 and 1996 NOTE 7. PRODUCT PRICE HEDGING CONTRACTS During June and July 1998, the Company entered into two no-cost financial contracts ("collars") to hedge a total of 40 million cubic feet of natural gas per day ("MMcf/d"). The first natural gas contract for 35 MMcf/d covers the period from July 1998 to June 1999 and has a floor price of $1.90 per million British Thermal Units ("MMBtu") and a ceiling price of $2.96 per MMBtu. The second natural gas contract for five MMcf/d covers the period from September 1998 to August 1999 and has a floor price of $1.90 per MMBtu and a ceiling price of $2.89 per MMBtu. During December 1998, the Company extended these natural gas hedges through December 2000 by entering into an additional no-cost collar with a floor price of $1.90 per MMBtu and a ceiling price of $2.58 per MMBtu for the period of July 1999 through December 2000. This contract hedges 25 MMcf/d for the months of July and August 1999 and 30 MMcf/d for each month thereafter. The Company collected $175,200 on these financial contracts during 1998. These three contracts cover over 100% of the Company's current net natural gas production. Based on the futures market prices at December 31, 1998, the Company would not receive or pay any amounts under these open commodity contracts even though they covered more than the Company's production because prices at December 31, 1998 were within the contract collars. During the fourth quarter of 1998, the Company also modified certain of its oil sales contracts. The new contracts which are generally for a period of eighteen months, provide that approximately 45% of the Company's oil production as of January 31, 1999, has a price floor of between $8.00 and $10.00 per Bbl. This equates to a NYMEX oil price of between $15.00 and $16.00 per bbl. As compensation for the price floors, the contracts provide that the premiums received on the posted prices decrease as oil prices rise. NOTE 8. COMMITMENTS AND CONTINGENCIES The Company has operating leases for the rental of office space, office equipment, and vehicles. At December 31, 1998, long-term commitments for these items require the following future minimum rental payments: AMOUNTS IN THOUSANDS 1999 .........................$ 593 2000 ......................... 1,274 2001 ......................... 1,259 2002 ......................... 1,242 2003 ......................... 1,120 -------------- Total lease commitments $ 5,488 ============== The Company is subject to various possible contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Although management believes it has complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. In addition, production rates, marketing and environmental matters are subject to regulation by various federal and state agencies. In June of 1997, a well blow-out occurred at the Lake Chicot Field, for which the Company is operator, in St. Martin Parish, Louisiana in which four individuals that were employees of other third party entities were killed, F - 19 Notes to Consolidated Financial Statements Years Ended December 31, 1998, 1997 and 1996 none of whom were employees or contractors of the Company. In connection with this blow-out, a lawsuit was filed on July 2, 1997, Barbara Trahan, et al .v. Mallard Bay Drilling L.L.C., Parker Drilling Company and Denbury Management, Inc., Case No. 58226-G in the 16th Judicial District Court in St. Martin Parish, Louisiana alleging various defective and dangerous conditions, violation of certain rules and regulations and acts of negligence. The Company believes that all litigation to which it is a party is covered by insurance and none of such legal proceedings can be reasonably expected to have a material adverse effect on the Company's financial condition, results of operations or cash flows. The Company and its subsidiaries are involved in various other lawsuits, claims and regulatory proceedings incidental to their businesses. In the opinion of management, the outcome of such matters will not have a material adverse effect on the Company's business, consolidated financial position, results of operations or cash flows. Uncertainty Due to the Year 2000 Issue The Year 2000 Issue arises because many computerized systems use two digits rather than four to identify a year. Date-sensitive systems may recognize the year 2000 as 1900 or some other date, resulting in errors when information using year 2000 dates is processed. In addition, similar problems may arise in some systems which use certain dates in 1999 to represent something other than a date. The effects of the Year 2000 Issue may be experienced before, on, or after January 2000, and, if not addressed, the impact on operations and financial reporting may range from minor errors to significant systems failure which could affect the Company's ability to conduct normal business operations. It is not possible to be certain that all aspects of the Year 2000 Issue affecting the Company, including those related to the efforts of customers, suppliers, or other third parties, will be fully resolved. NOTE 9. DIFFERENCES IN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES BETWEEN CANADA AND THE UNITED STATES The consolidated financial statements have been prepared in accordance with GAAP in Canada. The primary differences between Canadian and U.S. GAAP affecting the Company's consolidated financial statements are as discussed below. Loss on Extinguishment of Debt and Imputed Preferred Dividends The most significant GAAP difference relates to the presentation of the early extinguishment of debt and the imputed dividend on the Convertible Preferred. During 1996, the Company expensed $1,281,000 relating to the imputed preferred dividend, as required under Canadian GAAP. Under U.S. GAAP, this dividend would be deducted from net income to compute the net income attributable to the common shareholders. The Company also expensed its debt issue cost relating to the Company's prior bank credit agreements totaling $440,000 for 1996. Under Canadian GAAP this is an operating expense, while under U.S. GAAP a loss on early extinguishment of debt is an extraordinary item. While net income per common share and all balance sheet accounts are not affected by these differences in GAAP, the net income for 1996 under U.S. GAAP would be $10,025,000, while under Canadian GAAP the amount reported was $8,744,000. F - 20 Notes to Consolidated Financial Statements Years Ended December 31, 1998, 1997 and 1996 Earnings Per Share In addition, the methodology for computing fully diluted earnings per common share is not consistent between the two countries. For Canadian purposes, the proceeds from dilutive securities are used to reduce debt in the calculation. Under U.S. GAAP, Statement of Financial Accounting Standards ("SFAS") No. 128 requires the proceeds from such instruments be used to repurchase Common Shares. Under U.S. GAAP, fully diluted earnings per share for the year ended December 31, 1996, the only year with a difference, would be $0.63 as compared to the $0.62 reported under Canadian GAAP. Full Cost Accounting The U.S. full cost accounting rules differ from the Canadian full cost accounting guidelines followed by the Company. In determining the limitation on carrying values, U.S. accounting rules require the discounting of estimated future net revenues from its proved reserves at 10% using constant current prices following the guidelines of the Securities and Exchange Commission ("SEC"). The Canadian guidelines allow the use of either current prices or average prices in the calculations of future net revenues presented on an undiscounted basis, less estimated future administrative and financing costs, income taxes and future site restoration and abandonment costs. See also "Note 3. Property and Equipment" for a discussion of the application of these rules on the ceiling test calculation. Other Differences In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (the "Statement"), which establishes standards for accounting and reporting derivative instruments. SFAS No. 133 is effective for periods beginning after June 15, 1999; however, earlier application is permitted. Management is currently not planning on early adoption of this Statement and has not had an opportunity to evaluate the impact of the provisions of the Statement on the Company's consolidated financial statements. The implementation of SFAS No. 130, "Reporting Comprehensive Income" is required for all fiscal years beginning after December 15, 1997. The Company had no items that would be included in a Comprehensive Income Statement for any of the three years ended December 31, 1998. F - 21 Notes to Consolidated Financial Statements Years Ended December 31, 1998, 1997 and 1996 NOTE 10. SUPPLEMENTAL INFORMATION Significant Oil and Natural Gas Purchasers Oil and natural gas sales are made on a day-to-day basis or under short-term contracts at the current area market price. The loss of any purchaser would not be expected to have a material adverse effect upon operations. For the year ended December 31, 1998, the Company sold 10% or more of its net production of oil and natural gas to the following purchasers: Hunt Refining (34%), Natural Gas Clearinghouse (17%) and Genesis Crude Oil (11%). Costs Incurred The following table summarizes costs incurred and capitalized in oil and natural gas property acquisition, exploration and development activities. Property acquisition costs are those costs incurred to purchase, lease, or otherwise acquire property, including both undeveloped leasehold and the purchase of revenues in place. Exploration costs include costs of identifying areas that may warrant examination and in examining specific areas that are considered to have prospects containing oil and natural gas reserves, including costs of drilling exploratory wells, geological and geophysical costs and carrying costs on undeveloped properties. Development costs are incurred to obtain access to proved reserves, including the cost of drilling development wells, and to provide facilities for extracting, treating, gathering and storing the oil and natural gas. Costs incurred in oil and natural gas activities for the years ended December 31, 1998, 1997 and 1996 are as follows: YEAR ENDED DECEMBER 31, ----------------------------------------- AMOUNTS IN THOUSANDS 1998 1997 1996 ----------- ----------- ----------- Property acquisitions: Proved......................... $ 13,093 $ 149,145 $ 46,230 Unevaluated.................... 7,185 77,664 2,626 Exploration......................... 12,222 20,734 4,592 Development......................... 70,152 57,884 33,409 ----------- ----------- ----------- Total costs incurred $ 102,652 $ 305,427 $ 86,857 =========== =========== =========== Property Acquisitions On December 30, 1997, Denbury acquired producing oil and natural gas properties in Mississippi for approximately $202 million (the "Chevron Acquisition"). The acquisition included 122 wells, of which 96 wells will be Company operated. The Company funded this acquisition with bank financing from a revised and restated credit facility. This acquisition was accounted for under purchase accounting and the results of operations will be consolidated effective December 31, 1997. Pro forma results of operations of the Company as if the Chevron Acquisition had occurred at the beginning of each respective period are as follows: F - 22 Notes to Consolidated Financial Statements Years Ended December 31, 1998, 1997 and 1996 YEAR ENDED DECEMBER 31, -------------------------- 1997 1996 ---------- ----------- (AMOUNTS IN THOUSANDS EXCEPT PER SHARE AMOUNTS) (UNAUDITED) Revenues........................................$ 104,695 $ 77,311 Net income...................................... 9,966 5,342 Net income per common share: Basic...................................... 0.49 0.41 Fully diluted.............................. 0.48 0.41 In computing the pro forma results, depreciation, depletion and amortization expense was computed using the units of production method, and an adjustment was made to interest expense reflecting the bank debt that was required to fund the acquisition. The pro forma results does not reflect any increases in general and administrative expense. 11. CONDENSED CONSOLIDATING FINANCIAL INFORMATION Denbury Management, Inc. issued debt securities during February 1998 which are fully and unconditionally guaranteed by Denbury Resources Inc. Denbury Holdings Ltd. was merged into Denbury Resources Inc. in December 1997 and is not a guarantor of the debt. Condensed consolidating financial information for Denbury Resources Inc. and Subsidiaries as of December 31, 1998 and 1997 and for the years ended December 31, 1998, 1997 and 1996 is as follows: DENBURY RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS
DECEMBER 31, 1998 ------------------------------------------------------- Denbury Denbury Denbury Management, Resources Inc. Resources Inc. AMOUNTS IN THOUSANDS Inc. (Issuer) (Guarantor) Eliminations Consolidated ----------- ------------ ----------- ------------ ASSETS Current assets........................................$ 23,900 $ 34 $ - $ 23,934 Property and equipment (using full cost accounting)... 180,664 - - 180,664 Investment in subsidiaries (equity method)............ - (32,274) 32,274 - Other assets.......................................... 8,260 1 - 8,261 ----------- ------------ ----------- ------------ Total assets............................$ 212,824 $ (32,239) $ 32,274 $ 212,859 =========== ============ =========== ============ LIABILITIES AND SHAREHOLDERS' DEFICIT Current liabilities...................................$ 18,662 $ 26 $ - $ 18,688 Long-term liabilities................................. 226,436 - - 226,436 Shareholders'deficit.................................. (32,274) (32,265) 32,274 (32,265) ----------- ------------ ----------- ------------ Total liabilities and shareholders' deficit..... $ 212,824 $ (32,239) $ 32,274 $ 212,859 =========== ============ =========== ============
F - 23 Notes to Consolidated Financial Statements Years Ended December 31, 1998, 1997 and 1996
DECEMBER 31, 1997 ------------------------------------------------------- Denbury Denbury Denbury Management, Resources Inc. Resources Inc. AMOUNTS IN THOUSANDS Inc. (Issuer) (Guarantor) Eliminations Consolidated ----------- ------------ ----------- ------------ ASSETS Current assets........................................$ 33,017 $ 363 $ - $ 33,380 Property and equipment (using full cost accounting)... 408,832 - - 408,832 Investment in subsidiaries (equity method)............ - 159,892 (159,892) - Other assets.......................................... 5,234 102 - 5,336 ----------- ------------ ----------- ------------ Total assets............................$ 447,083 $ 160,357 $ (159,892) $ 447,548 =========== ============ =========== ============ LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities...................................$ 30,554 $ 134 $ - $ 30,688 Long-term liabilities................................. 256,637 - - 256,637 Shareholders' equity.................................. 159,892 160,223 (159,892) 160,223 ----------- ------------ ----------- ------------ Total liabilities and shareholders' equity...$ 447,083 $ 160,357 $ (159,892) $ 447,548 =========== ============ =========== ============
DENBURY RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (in thousands of U.S. dollars)
YEAR ENDED DECEMBER 31, 1998 ------------------------------------------------------- Denbury Denbury Denbury Management, Resources Inc. Resources Inc. AMOUNTS IN THOUSANDS Inc. (Issuer) (Guarantor) Eliminations Consolidated ------------ ------------ ----------- ------------ Revenues.....................................$ 83,504 $ 2 $ - $ 83,506 Expenses..................................... 386,094 177 - 386,271 ------------ ------------ ----------- ------------ Loss before: (302,590) (175) - (302,765) Equity in net losses of subsidiaries... - (286,970) 286,970 - ------------ ------------ ----------- ------------ Loss before income taxes..................... (302,590) (287,145) 286,970 (302,765) Income tax benefit........................... 15,620 - - 15,620 ------------ ------------ ----------- ------------ Net loss.....................................$ (286,970) $ (287,145) $ 286,970 $ (287,145) ============ ============ =========== ============
YEAR ENDED DECEMBER 31, 1997 ---------------------------------------------------------------------- Denbury Denbury Denbury Management, Denbury Resources Inc. Resources Inc. AMOUNTS IN THOUSANDS Inc. (Issuer) Holdings Ltd. (Guarantor) Eliminations Consolidated ------------ ----------- ------------ ----------- ------------- Revenues.....................................$ 86,451 $ - $ 150 $ (145) $ 86,456 Expenses..................................... 62,658 - 145 (145) 62,658 ------------ ----------- ------------ ----------- ------------- Income before: 23,793 - 5 - 23,798 Equity in net earnings of subsidiaries... - 14,898 14,898 (29,796) - ------------ ----------- ------------ ----------- ------------- Income before income taxes................... 23,793 14,898 14,903 (29,796) 23,798 Income tax provision......................... (8,895) - - - (8,895) ------------ ----------- ------------ ----------- ------------- Net income...................................$ 14,898 $ 14,898 $ 14,903 $ (29,796) $ 14,903 ============ =========== ============ =========== =============
F - 24 Notes to Consolidated Financial Statements Years Ended December 31, 1998, 1997 and 1996
YEAR ENDED DECEMBER 31, 1996 ---------------------------------------------------------------------- Denbury Denbury Denbury Management, Denbury Resources Inc. Resources Inc. AMOUNTS IN THOUSANDS Inc. (Issuer) Holdings Ltd. (Guarantor) Eliminations Consolidated ------------ ----------- ------------ ----------- ------------- Revenues.....................................$ 53,631 $ - $ 179 $ (161) $ 53,649 Expenses..................................... 38,008 - 1,746 (161) 39,593 ------------ ----------- ------------ ----------- ------------- Income (loss) before: 15,623 - (1,567) - 14,056 Equity in net earnings of subsidiaries.. - 10,311 10,311 (20,622) - ------------ ----------- ------------ ----------- ------------- Income before income taxes................... 15,623 10,311 8,744 (20,622) 14,056 Income tax provision......................... (5,312) - - - (5,312) ------------ ----------- ------------ ----------- ------------- Net income...................................$ 10,311 $ 10,311 $ 8,744 $ (20,622) $ 8,744 ============ =========== ============ =========== =============
NOTE 12. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED) Net proved oil and natural gas reserve estimates as of December 31, 1998, 1997 and 1996 were prepared by Netherland & Sewell, independent petroleum engineers located in Dallas, Texas. The reserves were prepared in accordance with guidelines established by the Securities and Exchange Commission and, accordingly, were based on existing economic and operating conditions. Oil and natural gas prices in effect as of the reserve report date were used without any escalation except in those instances where the sale is covered by contract, in which case the applicable contract prices including fixed and determinable escalations were used for the duration of the contract, and thereafter the last contract price was used (See "Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves" below for a discussion of the effect of the different prices on reserve quantities and values.) Operating costs, production and ad valorem taxes and future development costs were based on current costs with no escalation. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. Moreover, the present values should not be construed as the current market value of the Company's oil and natural gas reserves or the costs that would be incurred to obtain equivalent reserves. All of the reserves are located in the United States. F - 25 Notes to Consolidated Financial Statements Years Ended December 31, 1998, 1997 and 1996 Estimated Quantities of Reserves
YEAR ENDED DECEMBER 31, ----------------------------------------------------------------------- 1998 1997 1996 ---------------------- ---------------------- ---------------------- Oil Gas Oil Gas Oil Gas (MBbl) (MMcf) (MBbl) (MMcf) (MBbl) (MMcf) --------- ---------- ---------- --------- --------- ---------- BALANCE BEGINNING OF YEAR................... 52,018 77,191 15,052 74,102 6,292 48,116 Revisions of previous estimates.......... (7,267) (15,369) 3,398 1,098 (490) 3,737 Revisions due to price changes........... (14,921) (990) (1,525) (317) 1,053 402 Extensions, discoveries and other additions.......................... 678 1,951 6,373 11,205 3,492 5,480 Production............................... (4,965) (13,361) (2,884) (13,257) (1,500) (8,933) Acquisition of minerals in place......... 2,998 21 31,604 4,360 6,205 25,300 Sales of minerals in place............... (291) (640) - - - - --------- ---------- ---------- --------- --------- ---------- BALANCE AT END OF YEAR...................... 28,250 48,803 52,018 77,191 15,052 74,102 ========= ========== ========== ========= ========= ========== PROVED DEVELOPED RESERVES: Balance at beginning of year............. 31,355 69,805 13,371 58,634 5,290 34,894 Balance at end of year................... 20,357 44,995 31,355 69,805 13,371 58,634
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves ("Standardized Measure") does not purport to present the fair market value of the Company's oil and natural gas properties. An estimate of such value should consider, among other factors, anticipated future prices of oil and natural gas, the probability of recoveries in excess of existing proved reserves, the value of probable reserves and acreage prospects, and perhaps different discount rates. It should be noted that estimates of reserve quantities, especially from new discoveries, are inherently imprecise and subject to substantial revision. Under the Standardized Measure, future cash inflows were estimated by applying year-end prices, adjusted for fixed and determinable escalations, to the estimated future production of year-end proved reserves. The product prices used in calculating these reserves has varied widely during the three year period. These prices have a significant impact on both the quantities and value of the proven reserves as the reduced oil price causes wells to reach the end of their economic life much sooner and also makes certain proved undeveloped locations uneconomical, both of which reduce the reserves. The low prices also indirectly affect reserve quantities and values as the Company may postpone or cancel repairs and upgrades on oil wells which result in steeper than expected declines. The oil prices used in the December 31, 1996 reserve report were based on a West Texas Intermediate price of $23.39 per Bbl, with these representative prices adjusted by field to arrive at the appropriate corporate net price in accordance with the rules of the Securities and Exchange Commission. However, this price was reduced to $16.18 per Bbl at December 31, 1997 and further reduced to $9.50 as of December 31, 1998. The Company's average net realized oil prices used in the December 31, 1996, 1997 and 1998 reserve reports were $21.73, $14.43 and $7.37, respectively. The gas prices used in the reserve calculation also varied widely with a NYMEX Henry Hub price of $3.90 per MMBtu at December 31, 1996 and a price of $2.58 and $2.15 per MMBtu at December 31, 1997 and 1998, respectively. F - 26 Notes to Consolidated Financial Statements Years Ended December 31, 1998, 1997 and 1996 Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the statutory tax rate to the excess of pre-tax cash inflows over the Company's tax basis in the associated proved oil and natural gas properties. Tax credits and net operating loss carryforwards were also considered in the future income tax calculation. Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure.
DECEMBER 31, -------------------------------------------- AMOUNTS IN THOUSANDS 1998 1997 1996 -------------- ------------- ------------- Future cash inflows.................................................... $ 317,148 $ 957,718 $ 627,476 Future production costs................................................ (112,521) (285,968) (134,986) Future development costs............................................... (23,887) (68,287) (28,722) -------------- ------------- ------------- Future net cash flows before taxes .................................... 180,740 603,463 463,768 10% annual discount for estimated timing of cash flows............ (65,721) (242,134) (147,670) -------------- ------------- ------------- Discounted future net cash flows before taxes.......................... 115,019 361,329 316,098 Discounted future income taxes......................................... - (26,021) (74,226) -------------- ------------- ------------- STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS............... $ 115,019 $ 335,308 $ 241,872 ============== ============= =============
The following table sets forth an analysis of changes in the Standardized Measure of Discounted Future Net Cash Flows from proved oil and natural gas reserves:
YEAR ENDED DECEMBER 31, ---------------------------------------------- AMOUNTS IN THOUSANDS 1998 1997 1996 ------------- ------------- -------------- BEGINNING OF YEAR...................................................... $ 335,308 $ 241,872 $ 81,164 Sales of oil and natural gas produced, net of production costs......... (52,721) (63,115) (39,385) Net changes in sales prices............................................ (198,836) (132,905) 116,587 Extensions and discoveries, less applicable future development and production costs................................................ 6,605 75,632 34,113 Previously estimated development costs incurred........................ 30,742 10,088 5,278 Revisions of previous estimates, including revised estimates of development costs, reserves and rates of production................. (76,532) 264 7,747 Accretion of discount.................................................. 33,531 24,187 8,116 Purchase of minerals in place.......................................... 12,869 131,080 86,677 Sales of minerals in place............................................. (1,968) - - Net change in income taxes............................................. 26,021 48,205 (58,425) ------------- ------------- -------------- END OF YEAR............................................................ $ 115,019 $ 335,308 $ 241,872 ============= ============= ==============
F - 27 Notes to Consolidated Financial Statements Years Ended December 31, 1998, 1997 and 1996 UNAUDITED QUARTERLY INFORMATION The following table presents unaudited summary financial information on a quarterly basis for 1998 and 1997.
IN THOUSANDS EXCEPT PER SHARE AMOUNTS MARCH 31 JUNE 30 SEPT. 30 DECEMBER 31 - ----------------------------------------------- ------------------------------------------------------------------ 1998 - ---- Revenues $ 25,555 $ 22,883 $ 19,599 $ 15,469 Expenses 26,608 195,067 22,022 142,574 Net loss (608) (121,939)(c) (2,423) (162,103)(c) Net loss per share: (a) Basic (0.03) (4.57) (0.09) (6.05) Fully diluted (0.03) (4.57) (0.09) (6.05) Cash flow from operations (b) 11,455 9,052 6,817 2,772 Cash flow used for investing activities 26,689 50,120 17,781 9,207 Cash flow provided by financing activities 14,826 30,906 20,501 10,002 1997 - ---- Revenues $ 21,653 $ 19,015 $ 20,401 $ 25,387 Expenses 13,375 15,512 15,304 18,467 Net income 5,215 2,207 3,211 4,270 Net income per share: Basic 0.26 0.11 0.16 0.21 Fully diluted 0.24 0.11 0.15 0.20 Cash flow from operations (b) 14,922 12,001 13,243 16,441 Cash flow used for investing activities 15,572 21,427 35,012 235,548 Cash flow provided by financing activities 436 1,030 20,752 218,897 (a) Due to the significant variances between quarters in net income and average shares outstanding, the combined quarterly loss per share does not equal the reported loss per share for 1998. (b) Exclusive of the net change in non-cash working capital balances. (c) Includes full cost ceiling writedown of oil and natural gas properties of $165 million and $115 million for the quarters ended June 30, 1998 and December 31, 1998, respectively.
Common Stock Trading Summary The following table summarizes the high and low last reported sales prices on days in which there were trades of the Common Shares on The New York Stock Exchange ("NYSE"), NASDAQ and on The Toronto Stock Exchange ("TSE") (as reported by such exchange) for each quarterly period for the last two fiscal years. The trades on the NYSE / NASDAQ are reported in U.S. dollars and the TSE trades are reported in Canadian dollars. The Company's Common Shares were listed on NASDAQ from August 25, 1995 to May 8, 1997. The Common Shares have been listed on the NYSE since May 8, 1997. As of February 1, 1999, to the best of the Company's knowledge, the Common Shares were held of record by approximately 1,300 holders, of which approximately 300 were U.S. residents holding approximately 80% of the outstanding Common Shares of the Company. No Common Share dividends have been paid or are anticipated to be paid. (See also Note 6 to the Consolidated Financial Statements.) F - 28 Notes to Consolidated Financial Statements Years Ended December 31, 1998, 1997 and 1996
NYSE/NASDAQ (U.S. $) TSE (CDN $) HIGH LOW HIGH LOW - -------------------------------------------------------------------------------------------------------------------- 1998 - ---- First quarter 20.63 16.13 29.00 23.00 Second quarter 17.75 12.75 25.00 18.50 Third quarter 13.50 6.00 19.90 8.75 Fourth quarter 8.50 3.50 13.10 5.40 - -------------------------------------------------------------------------------------------------------------------- 1998 annual 20.63 3.50 29.00 5.40 - -------------------------------------------------------------------------------------------------------------------- 1997 - ---- First quarter 16.00 12.00 21.75 16.40 Second quarter 17.63 13.13 24.50 18.00 Third quarter 23.75 16.13 33.00 22.20 Fourth quarter 24.63 17.88 33.50 25.50 - -------------------------------------------------------------------------------------------------------------------- 1997 annual 24.63 12.00 33.50 16.40 - --------------------------------------------------------------------------------------------------------------------
________________________________________________________________________________ COMMENTS BY AUDITORS FOR U.S. READERS ON CANADA-U.S. REPORTING DIFFERENCE In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when the financial statements are affected by conditions and events that cast substantial doubt on the Company's ability to continue as a going concern, such as those described in Note 1 to the consolidated financial statements. Our report to the shareholders dated February 19, 1999 is expressed in accordance with Canadian reporting standards which do not permit a reference to such events and conditions in the auditors' report when these are adequately disclosed in the financial statements. Deloitte & Touche LLP Chartered Accountants Calgary, Alberta February 19, 1999 F - 29 -----END PRIVACY-ENHANCED MESSAGE-----